EXHIBIT 99.1
                                                                  ------------



                               ARC ENERGY TRUST



                         2005 ANNUAL INFORMATION FORM



                                MARCH 22, 2006



<PAGE>

                               TABLE OF CONTENTS

                                                                          PAGE

GLOSSARY OF TERMS............................................................1
SPECIAL NOTES TO READER......................................................2
ARC ENERGY TRUST.............................................................4
   General...................................................................4
   General Development of Our Business.......................................4
OUR BUSINESS.................................................................6
   Overview..................................................................6
   Our Organizational Structure..............................................7
   Management Policies.......................................................7
   Cash Distributions and Distribution Policy................................8
   Capital Expenditures......................................................8
   Potential Acquisitions....................................................8
STATEMENT OF RESERVES DATA AND OTHER OIL AND GAS INFORMATION.................8
   Disclosure of Reserves Data...............................................9
   Reserves Data (Constant Prices and Costs).................................9
   Reserves Data (Forecast Prices and Costs)................................11
   Definitions and Notes to Reserves Data Tables:...........................13
   Reconciliations of Changes in Reserves and Future Net Revenue............18
   Additional Information Relating to Reserves Data.........................19
   Other Oil and Gas Information............................................20
   Marketing Arrangements...................................................29
   Acquisitions and Dispositions............................................29
SHARE CAPITAL OF ARC RESOURCES..............................................29
   Common Shares............................................................29
   Exchangeable Shares......................................................30
   Second Preferred Shares..................................................31
OTHER INFORMATION RELATING TO OUR BUSINESS..................................31
   Borrowing................................................................31
   Restriction On Resale Agreements.........................................32
   Retention Payments.......................................................32
OUR INFORMATION.............................................................33
   Trust Units..............................................................33
   Special Voting Unit......................................................33
   the Trust Indenture......................................................33
   Trustee..................................................................33
   Future Offerings.........................................................34
   Meetings and Voting......................................................34
   Our Management...........................................................34
   Arc Financial Advisory Agreement.........................................35
   Limitation On Non-resident Ownership.....................................35
   Right of Redemption......................................................35
   Termination of the Trust.................................................36
   Reporting to Unitholders.................................................36
   Distribution Reinvestment and Optional Trust Unit Purchase Plan..........36

<PAGE>
                                      ii


CORPORATE GOVERNANCE........................................................36
   General..................................................................36
   Trust Indenture..........................................................37
   Decision Making..........................................................37
   Board of Directors of Arc Resources......................................37
AUDIT COMMITTEE DISCLOSURES.................................................41
CONFLICTS OF INTEREST.......................................................43
INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS..................43
DISTRIBUTIONS TO UNITHOLDERS................................................43
PRICE RANGE AND TRADING VOLUME OF TRUST UNITS AND EXCHANGEABLE SHARES.......44
STABILITY RATING............................................................45
INDUSTRY REGULATIONS........................................................45
   Pricing and Marketing of Oil and Natural Gas.............................45
   Pipeline Capacity........................................................46
   the North American Free Trade Agreement..................................46
   Provincial Royalties and Incentives......................................46
   Land Tenure..............................................................47
   Environmental Regulation.................................................47
RISK FACTORS................................................................48
   Volatility of Oil and Natural Gas Prices.................................48
   Reserves Estimates.......................................................48
   Variations in Interest Rates and Foreign Exchange Rates..................49
   Purchase of Properties...................................................49
   Enhanced Oil Recovery....................................................49
   Changes in Legislation...................................................49
   Maintenance of Distributions.............................................50
   Operational Matters......................................................51
   Expansion of Operations..................................................51
   Non-resident Ownership of Trust Units....................................51
   Accounting Write-downs as a Result of Gaap...............................51
   Environmental Concerns...................................................52
   Kyoto Protocol...........................................................52
   Debt Service.............................................................53
   Delay in Cash Distributions..............................................53
   Reliance On Management...................................................53
   Depletion of Reserves....................................................53
   Net Asset Value..........................................................54
   Additional Financing.....................................................54
   Competition..............................................................54
   Return of Capital........................................................54
   Nature of Trust Units....................................................55
   Unitholder Limited Liability.............................................55
   Title to Properties......................................................55

<PAGE>
                                     iii


TRANSFER AGENTS AND REGISTRARS..............................................56
MATERIAL CONTRACTS..........................................................56
INTEREST OF EXPERTS.........................................................56
ADDITIONAL INFORMATION......................................................57

APPENDIX A  -  REPORT ON RESERVES DATA BY INDEPENDENT QUALIFIED RESERVES
               EVALUATOR
APPENDIX B  -  REPORT OF MANAGEMENT AND DIRECTORS ON RESERVES DATA AND OTHER
               INFORMATION
APPENDIX C  -  MANDATE OF THE AUDIT COMMITTEE

<TABLE>
<CAPTION>
ABBREVIATIONS AND CONVERSIONS

<S>      <C>                                                     <C>      <C>
bbl      Barrel                                                  Mcf      one thousand cubic feet
bbl/d    barrels per day                                         Mcfpd    one thousand cubic feet per day
Bcf      billion cubic feet                                      MMBTU    one million British Thermal Units
boe      barrels of oil equivalent converting 6 Mcf of           MMcf     one million cubic feet
         natural gas or one barrel of natural gas liquids
         to one barrel of oil equivalent
                                                                 MMcfpd   one million cubic feet per day
                                                                 $MM      one million dollars
boe/d    barrels of oil equivalent per day                       MMbbl    one million barrels
Mbbl     one thousand barrels                                    NGLs     natural gas liquids
mboe     one thousand barrels of oil equivalent
</TABLE>

We have adopted the standard of 6Mcf:1boe when converting natural gas to boes.
Boes may be misleading,  particularly  if used in isolation.  A boe conversion
ratio of 6 Mcf per barrel is based on an energy equivalency  conversion method
primarily  applicable  at the  burner  tip  and  does  not  represent  a value
equivalency at the wellhead.

The following table sets forth certain standard  conversions  between Standard
Imperial Units and the International System of Units (or metric units).

    TO CONVERT FROM            TO                     MULTIPLY BY
    ---------------            --                     -----------
    cubic metres               cubic feet             35.315
    bbls                       cubic metres           0.159
    cubic metres               bbls                   6.290
    Feet                       metres                 0.305
    Metres                     feet                   3.281
    Miles                      kilometres             1.609
    Kilometres                 miles                  0.621
    Acres                      hectares               0.4047
    Hectares                   acres                  2.471

All dollar amounts set forth in this Annual  Information  Form are in Canadian
dollars, except where otherwise indicated.



<PAGE>

                               GLOSSARY OF TERMS

In this Annual Information Form, capitalized terms shall have the meanings set
forth below:

ACQUISITION means the acquisition by ARC Resources and its affiliates of three
unlimited liability corporations which together held the Acquisition Assets;

ACQUISITION  ASSETS  means  certain  properties  comprising  a 45.57%  working
interest in the North  Pembina  Cardium  Unit #1 in Alberta  and the  vendors'
working interests in the Redwater area of Alberta;

ARC,  WE,  US,  OUR or TRUST  means ARC  Energy  Trust and all its  controlled
entities as a consolidated body;

ARC RESOURCES means ARC Resources Ltd.;

ARC SASK. means ARC (Sask.) Energy Trust, an Alberta trust;

ARC SUBCO means  908563  Alberta  Ltd.,  or such other  corporation  as may be
substituted for ARC Subco;

ARML means ARC  Resources  Management  Ltd. a corporation  that,  prior to its
acquisition   by  ARC   Resources  in  connection   with  an   internalization
transaction, was responsible for our management;

EXCHANGEABLE  SHARES means the  exchangeable  shares of ARC Resources that are
exchangeable for Trust Units;

EXCHANGE  RATIO  means  the  ratio at which  the  Exchangeable  Shares  may be
exchanged for Trust Units;

GLJ means GLJ Petroleum Consultants Ltd., independent petroleum consultants of
Calgary, Alberta;

GLJ REPORT means the report prepared by GLJ dated February 23, 2006 evaluating
the  crude  oil,  natural  gas,  natural  gas  liquids  and  sulphur  reserves
attributable to the properties at December 31, 2005;

LONG TERM NOTES means the  unsecured  long term notes issued by ARC  Resources
and ARC Sask.  to the Trust from time to time  bearing  interest  at rates per
annum  ranging from 12 percent to 13 percent  payable  monthly  with  maturity
dates of 15 years from the date of issuance;

ROYALTIES means, collectively,  the royalties payable by ARC Resources and ARC
Sask. to the Trust pursuant to the royalty  agreements  which equal 99 percent
of royalty income;

SPECIAL DEBENTURE means the special 8 percent special  adjustable  convertible
subordinated  debenture  dated  April 16,  2003,  in the  principal  amount of
$320,000,000 issued by us as partial payment for Star Oil & Gas Ltd.;

TRUST INDENTURE means the trust indenture between  Computershare Trust Company
of Canada,  as trustee,  and ARC Resources Ltd., as amended and restated as of
May 12, 2005;

TRUST  UNITS  means the units of the Trust,  each unit  representing  an equal
undivided beneficial interest in the Trust; and

UNITHOLDERS means holders of Trust Units of the Trust.

Certain  other  terms used in this  Annual  Information  Form but not  defined
herein are defined in NI 51-101 and,  unless the context  otherwise  requires,
shall have the same meanings herein as in NI 51-101.

<PAGE>
                                      2


                            SPECIAL NOTES TO READER

REGARDING FORWARD LOOKING STATEMENTS

Certain  statements  contained in this Annual Information Form, and in certain
documents  incorporated  by  reference  into  this  Annual  Information  Form,
constitute  forward-looking  statements.  These  statements  relate  to future
events or our future  performance.  All  statements  other than  statements of
historical fact may be forward-looking statements.  Forward-looking statements
are  often,  but not  always,  identified  by the use of words such as "seek",
"anticipate",  "budget", "plan", "continue", "estimate", "expect", "forecast",
"may",  "will",  "project",  "predict",  "potential",  "targeting",  "intend",
"could",  "might",   "should",   "believe"  and  similar  expressions.   These
statements  involve known and unknown risks,  uncertainties  and other factors
that may cause  actual  results  or events to  differ  materially  from  those
anticipated in such  forward-looking  statements.  We believe the expectations
reflected in those forward-looking  statements are reasonable but no assurance
can be  given  that  these  expectations  will  prove to be  correct  and such
forward-looking  statements  included in, or  incorporated  by reference into,
this  Annual  Information  Form  should  not  be  unduly  relied  upon.  These
statements speak only as of the date of this Annual  Information Form or as of
the date specified in the documents incorporated by reference into this Annual
Information Form, as the case may be.

In particular, this Annual Information Form, and the documents incorporated by
reference, contain forward-looking statements pertaining to the following:

     o   the performance characteristics of our oil and natural gas properties;

     o   oil and natural gas production levels;

     o   the size of the oil and natural gas reserves;

     o   projections of market prices and costs and the related  sensitivities
         of distributions;

     o   supply and demand for oil and natural gas;

     o   expectations   regarding   the  ability  to  raise   capital  and  to
         continually add to reserves through acquisitions and development;

     o   treatment under governmental regulatory regimes and tax laws; and

     o   capital expenditures programs.

The actual  results could differ  materially  from those  anticipated in these
forward-looking statements as a result of the risk factors set forth below and
elsewhere in this Annual Information Form:

     o   volatility in market prices for oil and natural gas;

     o   liabilities inherent in oil and natural gas operations;

     o   uncertainties associated with estimating oil and natural gas reserves;

     o   competition  for,  among  other  things,  capital,   acquisitions  of
         reserves, undeveloped lands and skilled personnel;

     o   incorrect  assessments  of the  value,  or  failure  to  realize  the
         anticipated benefits of acquisitions, of acquisitions;

     o   geological, technical, drilling and processing problems;

     o   changes  in  income  tax laws or  changes  in tax laws and  incentive
         programs relating to the oil and gas industry and income trusts; and

     o   the other factors discussed under "RISK FACTORS".

The actual  results could differ  materially  from those  anticipated in these
forward-looking  statements,  which are based on assumptions,  including as to
the market  prices for oil and natural  gas;  the  continued  availability  of
capital,  acquisitions of reserves,  undeveloped lands and skilled  personnel;
the  continuation

<PAGE>
                                      3


of the current tax and regulatory  regime and other  assumptions  contained in
this Annual Information Form.

Statements   relating  to   "reserves"  or   "resources"   are  deemed  to  be
forward-looking  statements, as they involve the implied assessment,  based on
certain estimates and assumptions,  that the resources and reserves  described
can be profitably produced in the future.

Readers are cautioned that the foregoing  lists of factors are not exhaustive.
The forward-looking  statements  contained in this Annual Information Form and
the documents incorporated by reference herein are expressly qualified by this
cautionary statement. We do not undertake any obligation to publicly update or
revise any forward-looking statements.

DESCRIPTION OF CASH FLOW

This Annual Information Form refers to cash flow and cash flow from operations
derived from cash flow from operating  activities  (before changes in non-cash
working capital and  expenditures on site reclamation and  restoration).  Cash
flow as  presented  does not  have  any  standardized  meaning  prescribed  by
Canadian generally accepted accounting  principles,  ("GAAP") and therefore it
may not be  comparable  with the  calculation  of similar  measures  for other
entities.  Cash flow as presented is not intended to represent  operating cash
flow or  operating  profits  for the  period  nor  should  it be  viewed as an
alternative  to cash flow from  operating  activities,  net  earnings or other
measures of financial performance calculated in accordance with Canadian GAAP.

For  more  information,  see  "Management's  Discussion  and  Analysis"  which
includes a  reconciliation  of "cash flow" or "cash flow from  operations"  to
cash flow from  operating  activities  (before  changes  in  non-cash  working
capital and expenditures on site reclamation and restoration),  which has been
filed on SEDAR at WWW.SEDAR.COM.

ACCESS TO DOCUMENTS

Any document  referred to in this Annual  Information  and  described as being
filed on SEDAR at  WWW.SEDAR.COM  (including  those  documents  referred to as
being  incorporated  by  reference  in this  Annual  Information  Form) may be
obtained  free of charge  from us at 2100,  440 - 2nd  Avenue  S.W.,  Calgary,
Alberta, T2P 5E9.



<PAGE>
                                      4


                               ARC ENERGY TRUST

GENERAL

We are an open-end  investment  trust created on May 7, 1996 under the laws of
the Province of Alberta pursuant to the Trust Indenture.  Computershare  Trust
Company of Canada has been appointed as trustee under the Trust Indenture. The
beneficiaries  of the Trust are holders of the Trust Units.  The principal and
head  office of the  Trustee  is located  at Suite  600,  530 8th Avenue  SW.,
Calgary,  Alberta,  T2P 3S8. The Trust Indenture has been amended from time to
time, the latest  amendments  being approved at the annual and special meeting
of Unitholders held May 12, 2005.

The principal  offices of the Trust and ARC Resources are located at 2100, 440
- 2nd Avenue S.W.,  Calgary,  Alberta,  T2P 5E9 and its  registered  office is
located at 1400, 350 - 4th Avenue S.W., Calgary, Alberta, T2P 3N9.

The  following  are the name,  the  percentage  of voting  securities  and the
jurisdiction  governing our material  subsidiaries,  partnerships  and trusts,
either direct or indirect, as at the date hereof:

<TABLE>
<CAPTION>
                                          PERCENTAGE OF VOTING                         JURISDICTION OF
                                               SECURITIES                               INCORPORATION/
                                        (DIRECTLY OR INDIRECTLY)   NATURE OF ENTITY       FORMATION
                                        ------------------------   ----------------       ---------
<S>                                               <C>                <C>                   <C>
ARC Resources Ltd.                                100%               Corporation           Alberta
ARC Canadian Oil & Gas Ltd.                       100%               Corporation           Alberta
Orion Energy Trust                                100%                  Trust              Alberta
ARC (Sask.) Energy Trust                          100%                  Trust              Alberta
</TABLE>


GENERAL DEVELOPMENT OF OUR BUSINESS

The following  equity  offerings were completed over the last three  financial
years.

<TABLE>
<CAPTION>
               PROSPECTUS   TRUST UNITS     ISSUE
 CLOSING DATE     DATE         ISSUED       PRICE    GROSS PROCEEDS                USE OF PROCEEDS
 ------------     ----         ------       -----    --------------                ---------------
<C>             <C>          <C>           <C>        <C>             <C>
25-Feb-03       13-Feb-03    12,500,000    $11.50     $143,750,000    Repay outstanding indebtedness and
                                                                      partially fund 2003 capital program

17-Nov-03       10-Nov-03    14,500,000    $13.40     $194,300,000    Repay outstanding indebtedness and
                                                                      partially fund 2004 capital program

23-Dec-05       16-Dec-05    9,000,000     $26.65     $239,850,000    Repay outstanding indebtedness,
                                                                      including the indebtedness incurred
                                                                      in connection with the Acquisition
</TABLE>

A description  of the general  development of our business over the last three
financial years follows.

On March 31, 2003 we entered  into an  agreement  with  United  Energy LLC and
acquired  all the  shares  of Star Oil & Gas  Ltd.  for  $710,000,000  (before
closing  adjustments)  effective January 1, 2003. We paid for this acquisition
by issuing the Special  Debenture for $320,000,000,  repaying  $187,372,000 of
corporate  and  shareholder  debt and  payment  of  $202,628,000  in cash.  We
concurrently  agreed to sell our interest in

<PAGE>
                                      5


certain  producing  properties  and  undeveloped  acreage to third parties for
$78,200,000.  We increased our aggregate credit  facilities to $650,000,000 to
finance the transaction, which closed on April 16, 2003.

The Special Debenture was fully converted into Trust Units as follows.  On May
20, 2003,  United ARC L.P.  converted  $200,000,000  of principal  amount into
16,891,891  Trust  Units at $11.84 per Trust  Unit.  United ARC L.P.  sold the
16,891,891  Trust  Units  and  remaining  $120,000,000  principal  amount in a
secondary  offering  to the  public.  By August  1, 2003 all of the  remaining
Special  Debenture was fully converted into 10,135,131  Trust Units at a price
of $11.84 per Trust Unit.

On August 15,  2003,  we  disposed  of non core  assets to third  parties  for
approximately $77,000,000.  Net production represented by these properties was
approximately  3,700 boe/d.  Concurrent with the  disposition,  we reduced our
borrowing base from  $650,000,000 to  $620,000,000.  We used the proceeds from
the disposition to reduce our outstanding indebtedness.

On June 8,  2004,  we  acquired  the  remaining  30 percent  ownership  of the
Cranberry  Slave  Point D Pool in the  Prestville  area in  northern  Alberta,
through the purchase of United  Prestville  Ltd. We paid for this  acquisition
with the  issuance  of  2,032,358  Trust  Units at a price of $15.01 per Trust
Unit.

On December 31, 2004, we acquired all of the issued and outstanding  shares of
four legal entities - Harrington Oil & Gas Ltd.,  Bibler Oil & Gas Ltd., Lesco
Oil & Gas Ltd., and Bibco Oil & Gas Ltd. for approximately $41.4 million.  All
of the assets  acquired  are  long-life  shallow  gas assets in our  southwest
Saskatchewan/southeast  Alberta core area, with almost 60 percent of the value
attributed to properties operated by us.

On June 30,  2005,  we acquired  all of the issued and  outstanding  shares of
Romulus  Exploration Inc. for total  consideration  of $42.2 million.  The key
property in this acquisition is directly  adjacent to ARC's Weir Hill property
in Southeast Saskatchewan.

On December 16,  2005,  we acquired  the  Acquisition  Assets for an aggregate
purchase  price of  approximately  $462.8  million.  In  conjunction  with the
Acquisition,  ARC Resources agreed to form a reclamation  trust in relation to
the Redwater  properties  pursuant to which ARC Resources agreed to contribute
to such trust certain minimum  amounts,  totaling  approximately  $110 million
over  a  50  year  period,  to  fund  future   environmental  and  reclamation
obligations  in  respect  of the  Redwater  properties,  or to expend  certain
minimum  amounts towards  discharging  these  obligations.  The amount will be
contributed  or  expenditures  incurred  over such period with minimum  annual
contributions  or  expenditures  over  each  of  the  initial  five  years  of
approximately $6 million and declining thereafter.  Concurrently, we increased
our credit  facility from $620 million to $950 million in order to pay for the
Acquisition  and on December 23, 2005  decreased our  indebtedness  by the net
proceeds form the sale of 9,000,000 Trust Units at a price of $26.65 per Trust
Unit. For additional information in relation to the Acquisition,  reference is
made to the Business  Acquisition  Report dated January 4, 2006 filed on SEDAR
at   www.sedar.com,   which  is  incorporated  by  reference  in  this  Annual
Information Form.



<PAGE>
                                      6


                                 OUR BUSINESS

OVERVIEW

Our  principal  undertaking  is to  receive  Royalties  and  other  income  on
petroleum  and natural gas  properties  and related  assets and to acquire and
hold securities of subsidiaries,  trusts and  partnerships.  Our subsidiaries,
trusts and  partnerships  are entitled to carry on the business of  acquiring,
developing,  exploiting and disposing of all types of energy business  related
assets,  including  petroleum  and  natural  gas  related  assets,  oil  sands
interests,  electricity or power  generating  assets and pipeline,  gathering,
processing and transportation  assets. We issue Trust Units and may also issue
securities  of ARC  Resources  or an  affiliate  of ARC  Resources  which  are
exchangeable for Trust Units and confer voting rights in us.

Our principal  investments  are the Royalties  granted by ARC Resources and by
ARC Sask.,  the common  shares of ARC  Resources,  the Long Term Notes and the
common  shares of ARC Canadian Oil & Gas Ltd.  The  Royalties  consist of a 99
percent share of royalty income on all of the properties held by ARC Resources
and ARC Sask.  Royalty  income is generally  all  production  revenue less all
operating and capital costs and all debt service charges  including  principal
repayments. On each monthly distribution date, ARC Resources and ARC Sask. pay
the Trust 99 percent of royalty  income and ARC Resources  and ARC Sask.  pays
interest  on   outstanding   Long  Term  Notes.   The  Trust  will  make  cash
distributions of such funds,  subject only to the required  deductions and its
expenses.  Such  cash  distributions  may be wholly  or in part  taxable.  See
"Distributions to Unitholders".

We are structured with the objective of having income tax incurred only in the
hands of Unitholders.  Income distributed to Unitholders  consists essentially
of operating cash flow generated by our oil and natural gas  properties.  More
specifically,  internally generated cash flow, with the exception of cash flow
used  for  capital  expenditures,  reclamation  fund  contributions,  interest
expense and debt repayments, is effectively returned to Unitholders.

As an open-ended  investment  trust  Unitholders  have a right to redeem their
Trust Units.  As with most other  open-ended  funds,  it is  anticipated  that
trading  on the TSX and not the  right of  retraction  would  continue  as the
primary mechanism for Unitholders to sell their Trust Units. For more detailed
information regarding the right of redemption, see "Our Information - Right of
Redemption".

As at December 31, 2005,  we had  approximately  375  employees  and full time
consultants.


<PAGE>
                                      7


OUR ORGANIZATIONAL STRUCTURE

Our structure and the cash flows from our material subsidiaries and trusts to
Unitholders are set forth below:

         [GRAPHIC OMITTED -- ORGANIZATIONAL CHART]


Notes:
(1)  ARC Resources is the holder of  substantially  all  properties and assets
     other than the properties and assets  located in  Saskatchewan  which are
     held by ARC  (Sask.).  Properties  in  British  Columbia  are held by ARC
     Petroleum Inc. as trustee and agent of ARC Resources.

(2)  ARC Resources had a total of 1,594,396 Exchangeable Shares outstanding as
     at December 31, 2005 that were exchangeable for  approximately  2,933,640
     Trust Units.

MANAGEMENT POLICIES

All our activities are directed  towards  maximizing  distributable  income to
Unitholders  while at the same time striving for long-term growth in the value
of our assets.  These two objectives are fundamental to our operations and are
balanced to maximize benefit to Unitholders. We direct our efforts to increase
the value of our assets  through  the  acquisition  of  producing  oil and gas
properties.  We acquire  producing  properties  and primarily  participate  in
development  activities  that  are  generally  considered  to be of a low risk
nature in the oil and gas  industry.  Also, a small  percentage of each year's
capital  budget will be devoted to moderate  risk  development  and lower risk
exploration opportunities on our properties.

<PAGE>
                                      8


CASH DISTRIBUTIONS AND DISTRIBUTION POLICY

Cash distributions are made on the 15th day (or if such date is not a business
day, on the next  business day)  following  the end of each calendar  month to
Unitholders of record on the last business day of each such calendar month.

The Board of  Directors of ARC  Resources  on behalf of the Trust  reviews the
distribution policy from time to time. The actual amount distributed is at the
discretion of the Board of Directors  and is  principally  dependent  upon the
commodity  price  environment and the amount of cash flow withheld to fund the
Trust's capital expenditure program and the annual contribution to the Trust's
reclamation  fund. In times of high  commodity  prices,  we withhold a greater
percentage  of cash flow so that  more of the  capital  program  can be funded
internally.

Although our  distributions  are made on a monthly basis, we normally announce
distribution  levels on a quarterly  basis.  As we strive for stability in our
distributions,  any changes which may occur due to varying  market  conditions
will be made with a view to maintaining the new level of distributions  for at
least three months.

CAPITAL EXPENDITURES

We may acquire  additional  properties and related tangible equipment and fund
such acquisitions from production  revenues,  the net proceeds of any issue of
additional  Trust Units or from the proceeds of  disposition  of the Royalties
sold along with  properties,  or from  borrowings,  farmouts  or with  working
capital.  We may sell any of our  interests  in  properties  and  release  the
Royalties from such properties in consideration of the allocation of a portion
of the proceeds to the Trust,  provided that the sale is approved by a special
resolution of Unitholders  in the event the interests in the properties  being
sold constitute  greater than 25 percent of the asset value of all properties.
In  connection  with  the sale of any  interests  in the  properties,  we will
determine  whether  the net  proceeds  of the sale  should  be  reinvested  in
additional  properties,  used to repay borrowings or make capital expenditures
in ARC Resources or ARC Sask. or be distributed to Unitholders.

We may approve future capital  expenditures or farmouts under the terms of the
royalty  agreements.  Future  capital  expenditures  on  the  properties  will
generally be of the type that are  intended to maintain or improve  production
from the  properties.  We may finance  capital  expenditures  from  production
revenues,  the  proceeds  of the issue of  additional  Trust Units or from the
proceeds  of  disposition  of  the  Royalties  sold  along  with   properties,
borrowings, farmouts or with working capital.

POTENTIAL ACQUISITIONS

We continue to evaluate  potential  acquisitions of all types of petroleum and
natural gas and other energy-related assets as part of our ongoing acquisition
program.  We are  normally  in the  process of  evaluating  several  potential
acquisitions at any one time which individually or together could be material.
We cannot predict whether any current or future  opportunities  will result in
one or more acquisitions.

         STATEMENT OF RESERVES DATA AND OTHER OIL AND GAS INFORMATION

The statement of reserves data and other oil and gas  information is set forth
below (the  "Statement").  The effective date of the Statement is December 31,
2005 and the preparation date of the Statement is February 1, 2006. The Report
of Management and Directors on Oil and Gas Disclosure on Form 51-101F3 and the
Report on Reserves  Data by GLJ on Form  51-102F2 are attached as Appendices A
and B to this Annual Information Form.

<PAGE>
                                      9


DISCLOSURE OF RESERVES DATA

The reserves  data set forth below is based upon an  evaluation by GLJ with an
effective date of December 31, 2005 contained in the GLJ Report dated February
23,  2006.  The  reserves  data  summarizes  our oil,  liquids and natural gas
reserves and the net present  values of future net revenue for these  reserves
using  constant  prices  and  costs and  forecast  prices  and costs  prior to
provision for income taxes, interest, general and administrative expenses, the
impact of any hedging  activities  or the  liability  associated  with certain
abandonment and well, pipeline and facilities reclamation costs which were not
deducted by GLJ in estimating  future net revenue.  The reserves data conforms
with the requirements of NI 51-101. We engaged GLJ to provide an evaluation of
proved and proved plus probable  reserves.  See also "Definitions and Notes to
Reserves Data Tables" below.

All of our  reserves  are in Canada and,  specifically,  in the  provinces  of
Alberta, British Columbia and Saskatchewan.

IT SHOULD NOT BE ASSUMED THAT THE  ESTIMATES OF FUTURE NET REVENUES  PRESENTED
IN THE TABLES BELOW REPRESENT THE FAIR MARKET VALUE OF THE RESERVES.  THERE IS
NO  ASSURANCE  THAT THE  CONSTANT  PRICES AND COSTS  ASSUMPTIONS  AND FORECAST
PRICES AND COSTS ASSUMPTIONS WILL BE ATTAINED AND VARIANCES COULD BE MATERIAL.
THE  RECOVERY AND  RESERVES  ESTIMATES  OF CRUDE OIL,  NATURAL GAS LIQUIDS AND
NATURAL  GAS  RESERVES  PROVIDED  HEREIN  ARE  ESTIMATES  ONLY AND THERE IS NO
GUARANTEE  THAT THE ESTIMATED  RESERVES  WILL BE RECOVERED.  ACTUAL CRUDE OIL,
NATURAL GAS AND NATURAL GAS LIQUID  RESERVES  MAY BE GREATER THAN OR LESS THAN
THE ESTIMATES  PROVIDED HEREIN. FOR MORE INFORMATION AS TO THE RISKS INVOLVED,
SEE "RISK FACTORS - RESERVES  ESTIMATES" AND "RISK FACTORS - VOLATILITY OF OIL
AND NATURAL GAS PRICES".

RESERVES DATA (CONSTANT PRICES AND COSTS)

                        SUMMARY OF OIL AND GAS RESERVES
                 AND NET PRESENT VALUES OF FUTURE NET REVENUE
                            as of December 31, 2005
                           CONSTANT PRICES AND COSTS

                                                RESERVES
                                --------------------------------------
                                 LIGHT AND MEDIUM OIL       HEAVY OIL
                                ---------------------- ---------------
                                 Gross         Net      Gross     Net
RESERVES CATEGORY                (Mbbl)      (Mbbl)     (Mbbl)  (Mbbl)
-----------------                ------      ------     ------  ------

PROVED
     Developed Producing        100,659      89,764     2,757   2,791
     Developed Non-Producing      1,749       1,549         0       0
     Undeveloped                 13,819      11,940        40      34
                                -------     -------     -----   -----
TOTAL PROVED                    116,228     103,253     2,797   2,824

PROBABLE                         29,146      25,361       725     701
                                -------     -------     -----   -----
TOTAL PROVED PLUS PROBABLE      145,374     128,614    3,522    3,526
                                =======     =======    =====    =====


<PAGE>
                                      10


                                             RESERVES
                                 -------------------------------------
                                   NATURAL GAS     NATURAL GAS LIQUIDS
                                 ---------------  --------------------
                                 Gross     Net     Gross          Net
RESERVES CATEGORY                (MMcf)  (MMcf)   (Mbbl)        (Mbbl)
-----------------                ------  ------   ------        ------

PROVED
     Developed Producing        452,221  383,475   10,269        7,394
     Developed Non-Producing     15,744   12,436      431          312
     Undeveloped                119,017   97,363    1,347          947
TOTAL PROVED                    586,981  493,275   12,047        8,652

PROBABLE                        145,504  120,877    2,853        2,087
                                -------  -------   ------        -----
TOTAL PROVED PLUS PROBABLE      732,485  614,151   14,900       10,739
                                =======  =======   ======       ======


                                    RESERVES
                                -----------------
                                      TOTAL
                                -----------------
                                 Gross      Net
RESERVES CATEGORY                (mboe)   (mboe)
-----------------                ------   ------

PROVED
     Developed Producing        189,056  163,861
     Developed Non-Producing      4,804    3,934
     Undeveloped                 35,042   29,148
                                -------  -------
TOTAL PROVED                    228,902  196,942

PROBABLE                         56,974   48,295
                                -------  -------
TOTAL PROVED PLUS PROBABLE      285,876  245,237
                                =======  =======


                                                 NET PRESENT VALUES OF
                                                  FUTURE NET REVENUE
                                            ---------------------------
                                                  BEFORE INCOME TAXES
                                                DISCOUNTED AT (%/year)
                                            ---------------------------
                                                0%                10%
RESERVES CATEGORY                             (MM$)              (MM$)
-----------------                             -----              -----

PROVED
   Developed Producing                       6,925.7            3,726.4
   Developed Non-Producing                     174.0               93.8
   Undeveloped                               1,069.1              482.0
                                            --------            -------
TOTAL PROVED                                 8,168.8            4,302.1

PROBABLE                                     2,049.3              667.7
                                            --------            -------
TOTAL PROVED PLUS PROBABLE                  10,218.1            4,969.8
                                            ========            =======

<PAGE>
                                        11

<TABLE>
<CAPTION>
                                           TOTAL FUTURE NET REVENUE
                                                (UNDISCOUNTED)
                                            as of December 31, 2005
                                           CONSTANT PRICES AND COSTS

                                                                                  FUTURE NET              FUTURE NET
                                                                        WELL       REVENUE                 REVENUE
                                         OPERATING    DEVELOPMENT   ABANDONMENT     BEFORE      INCOME       AFTER
    RESERVES       REVENUE   ROYALTIES     COSTS         COSTS         COSTS     INCOME TAXES    TAXES   INCOME TAXES
    CATEGORY        (MM$)      (MM$)       (MM$)         (MM$)         (MM$)        (MM$)        (MM$)      (MM$)
    --------        -----      -----       -----         -----         -----        -----        -----      -----
<S>               <C>         <C>          <C>          <C>           <C>         <C>            <C>       <C>
Proved Reserves   13,978.1    2,157.5      3,072.1      455.7         124.0       8,168.8        0         8,168.8

Proved Plus       17,395.8    2,742.9      3,685.3      619.6         129.9      10,218.1        0        10,218.1
Probable
Reserves
</TABLE>

<TABLE>
<CAPTION>
                                              FUTURE NET REVENUE
                                              BY PRODUCTION GROUP
                                           as of December 31, 2005
                                          CONSTANT PRICES AND COSTS
                                                                                 FUTURE NET REVENUE BEFORE
                                                                                INCOME TAXES (discounted at
                                                                                         10%/year)
        RESERVES CATEGORY                           PRODUCTION GROUP                       (MM$)
        -----------------                           ----------------            ---------------------------
<S>                                 <C>                                                    <C>
Proved Reserves                     Light and Medium Crude Oil                             2,410.8
                                    Heavy Oil                                                 43.7
                                    Natural Gas                                            1,838.0

Proved Plus Probable Reserves       Light and Medium Crude Oil                             2,805.4
                                    Heavy Oil                                                 50.6
                                    Natural Gas                                            2,104.4
</TABLE>
Notes:
(1)  The total  amounts for the future net reserves  from the proved  reserves
     and the probable  reserves do not  correspond  to the totals set forth in
     previous  tables because ARTC has not been allocated  amongst  production
     groups.

(2)  The unallocated  portion for proved reserves and for proved plus probable
     reserves are $9.7 MM, and $9.5 MM, respectively.

RESERVES DATA (FORECAST PRICES AND COSTS)

<TABLE>
<CAPTION>
                                                SUMMARY OF OIL AND GAS RESERVES
                                         AND NET PRESENT VALUES OF FUTURE NET REVENUE
                                                    as of December 31, 2005
                                                   FORECAST PRICES AND COSTS

                                                           RESERVES
                                   ------------------------------------------------------
                                       LIGHT AND MEDIUM OIL             HEAVY OIL
                                   --------------------------  --------------------------
                                    Gross            Net          Gross          Net
RESERVES CATEGORY                   (Mbbl)         (Mbbl)         (Mbbl)        (Mbbl)
-----------------                   ------         ------         ------        ------
<S>                                 <C>             <C>           <C>            <C>
PROVED
     Developed Producing             98,844          88,083       2,692          2,725
     Developed Non-Producing          1,760           1,559           0              0
     Undeveloped                     13,863          12,032          40             34
                                    -------         -------       -----          -----
TOTAL PROVED                        114,467         101,674       2,732          2,758

PROBABLE                             29,948          26,139         726            699
                                    -------         -------       -----          -----
TOTAL PROVED PLUS PROBABLE          144,414         127,813       3,457          3,458
                                    =======         =======       =====          =====
</TABLE>

<PAGE>
                                      12

<TABLE>
<CAPTION>
                                                          RESERVES
                                   --------------------------------------------------
                                         NATURAL GAS            NATURAL GAS LIQUIDS
                                   --------------------------  ----------------------
                                    Gross            Net          Gross       Net
RESERVES CATEGORY                   (MMcf)         (MMcf)         (Mbbl)     (Mbbl)
-----------------                   ------         ------         ------     ------
<S>                                 <C>             <C>           <C>        <C>
PROVED
     Developed Producing            448,241         380,057       10,192     7,358
     Developed Non-Producing         15,737          12,428          433       314
     Undeveloped                    118,645          97,016        1,346       948
                                    -------         -------       ------     -----
TOTAL PROVED                        582,623         489,501       11,970     8,621

PROBABLE                            143,974         119,488        2,853     2,093
                                    -------         -------       ------     -----
TOTAL PROVED PLUS PROBABLE          726,597         608,988       14,824    10,713
                                    =======         =======       ======    ======
</TABLE>


                                          RESERVES
                                -----------------------------
                                            TOTAL
                                -----------------------------
                                    Gross            Net
RESERVES CATEGORY                   (mboe)         (mboe)
-----------------                   ------         ------

PROVED
     Developed Producing           186,434         161,509
     Developed Non-Producing         4,815           3,944
     Undeveloped                    35,023          29,184
                                   -------         -------
TOTAL PROVED                       226,273         194,636

PROBABLE                            57,522          48,846
                                   -------         -------
TOTAL PROVED PLUS PROBABLE         283,795         243,482
                                   =======         =======

<TABLE>
<CAPTION>
                                                      NET PRESENT VALUES OF FUTURE NET REVENUE
                                                     BEFORE INCOME TAXES DISCOUNTED AT (%/year)
                                      ----------------------------------------------------------------------
                                          0%              5%             10%            15%             20%
RESERVES CATEGORY                        (MM$)          (MM$)           (MM$)          (MM$)           (MM$)
-----------------                        -----          -----           -----          -----           -----
<S>                                   <C>            <C>             <C>            <C>             <C>
PROVED
   Developed Producing                5,245.0        3,748.2         3,009.7        2,562.2         2,256.8
   Developed Non-Producing              134.9           94.0            73.3           60.6            52.0
   Undeveloped                          741.0          466.2           314.9          221.2           158.6
                                      -------        -------         -------        -------         -------
TOTAL PROVED                          6,120.9        4,308.5         3,397.9        2,844.1         2,467.4

PROBABLE                              1,626.7          805.7           493.1          339.7           251.3
                                      -------        -------         -------        -------         -------
TOTAL PROVED PLUS PROBABLE            7,747.5        5,114.2         3,891.0        3,138.8         2,718.7
                                      =======        =======         =======        =======         =======
</TABLE>

<PAGE>
                                      13

<TABLE>
<CAPTION>
                                                   TOTAL FUTURE NET REVENUE
                                                        (UNDISCOUNTED)
                                                     as December 31, 2005
                                                   FORECAST PRICES AND COSTS

                                                                                   FUTURE NET              FUTURE NET
                                                                        WELL        REVENUE                 REVENUE
                                          OPERATING   DEVELOPMENT   ABANDONMENT      BEFORE      INCOME       AFTER
    RESERVES       REVENUE   ROYALTIES      COSTS        COSTS         COSTS      INCOME TAXES    TAXES   INCOME TAXES
    CATEGORY        (MM$)      (MM$)        (MM$)        (MM$)         (MM$)         (MM$)        (MM$)      (MM$)
    --------        -----      -----        -----        -----         -----         -----        -----      -----
<S>               <C>          <C>         <C>         <C>            <C>           <C>           <C>       <C>
Proved Reserves   12,523.1     1,895.9     3,834.0     487.6          184.8         6,120.9       0         6,120.9

Proved Plus       15,910.6     2,432.3     4,859.1     662.9          208.9         7,747.5       0         7,747.5
Probable
Reserves
</TABLE>

<TABLE>
<CAPTION>
                                              FUTURE NET REVENUE
                                              BY PRODUCTION GROUP
                                            as of December 31, 2005
                                           FORECAST PRICES AND COSTS
                                                                                    FUTURE NET REVENUE
                                                                                    BEFORE INCOME TAXES
                                                                                  (discounted at 10%/year)
  RESERVES CATEGORY                           PRODUCTION GROUP                              (MM$)
  -----------------                           ----------------                    ------------------------
<S>                                 <C>                                                    <C>
Proved Reserves                     Light and Medium Crude Oil                             1,883.5
                                    Heavy Oil                                                 44.0
                                    Natural Gas                                            1,460.9

Proved Plus Probable Reserves       Light and Medium Crude Oil                             2,188.3
                                    Heavy Oil                                                 50.6
                                    Natural Gas                                            1,642.7
</TABLE>

Notes:
(1)  The total amounts for the future net reserves from the proved reserves do
     not  correspond to the totals set forth in previous  tables  because ARTC
     has not been allocated amongst production groups.

(2)  The unallocated  portion for proved reserves and for proved plus probable
     reserves are $9.6 MM and $9.4 MM, respectively.

DEFINITIONS AND NOTES TO RESERVES DATA TABLES:

In the tables set forth above in  "Disclosure  of Reserves Data" and elsewhere
in this Annual Information Form the following  definitions and other notes are
applicable:

1.   "GROSS" means:

     (a)  in relation to our interest in production and reserves, our interest
          (operating  and  non-operating)  before  deduction of royalties  and
          without including any royalty interest of us;

     (b)  in relation to wells,  the total number of wells in which we have an
          interest; and

     (c)  in relation to properties,  the total area of properties in which we
          have an interest.

2.   "NET" means:

     (a)  in relation to our interest in production and reserves, our interest
          (operating   and   non-operating)   after   deduction  of  royalties
          obligations, plus our royalty interest in production or reserves;

<PAGE>
                                      14


     (b)  in relation to wells,  the number of wells  obtained by  aggregating
          our working interest in each of our gross wells; and

     (c)  in relation to our  interest in a property,  the total area in which
          we have an interest multiplied by the working interest we owned.

3.   Columns may not add due to rounding.

4.   The crude oil,  natural gas liquids  and natural gas  reserves  estimates
     presented in the GLJ Report are based on the  definitions  and guidelines
     contained  in  the  Canadian  Oil  and  Gas  Evaluation   Handbook  (COGE
     Handbook). A summary of those definitions are set forth below:

RESERVES CATEGORIES

     Reserves are  estimated  remaining  quantities of oil and natural gas and
     related   substances   anticipated   to   be   recoverable   from   known
     accumulations,  from a given date forward, based on analysis of drilling,
     geological,  geophysical  and  engineering  data;  the use of established
     technology; and specified economic conditions.

     Reserves are classified  according to the degree of certainty  associated
     with the estimates.

     (a)  PROVED RESERVES are those reserves that can be estimated with a high
          degree of certainty to be recoverable.  It is likely that the actual
          remaining  quantities  recovered  will exceed the  estimated  proved
          reserves.

     (b)  PROBABLE  RESERVES  are  those  additional  reserves  that  are less
          certain to be recovered than proved  reserves.  It is equally likely
          that the actual  remaining  quantities  recovered will be greater or
          less than the sum of the estimated proved plus probable reserves.

     Other criteria that must also be met for the  categorization  of reserves
     are provided in the COGE Handbook.

     Each of the reserves categories (proved and probable) may be divided into
     developed and undeveloped categories:

     (c)  DEVELOPED  RESERVES  are  those  reserves  that are  expected  to be
          recovered  from  existing  wells  and  installed  facilities  or, if
          facilities  have  not  been  installed,  that  would  involve  a low
          expenditure  (for  example,  when compared to the cost of drilling a
          well) to put the reserves on production.  The developed category may
          be subdivided into producing and non-producing.

          (i)  DEVELOPED  PRODUCING  RESERVES  are  those  reserves  that  are
               expected to be recovered from completion  intervals open at the
               time of the estimate. These reserves may be currently producing
               or, if shut-in,  they must have  previously been on production,
               and the date of  resumption  of  production  must be known with
               reasonable certainty.

          (ii) DEVELOPED NON-PRODUCING RESERVES are those reserves that either
               have  not  been  on  production,  or  have  previously  been on
               production,  but are  shut-in,  and the date of  resumption  of
               production is unknown.

<PAGE>
                                      15


     (d)  UNDEVELOPED  RESERVES  are those  reserves  expected to be recovered
          from  known  accumulations  where  a  significant  expenditure  (for
          example,  when  compared to the cost of drilling a well) is required
          to render  them  capable  of  production.  They must  fully meet the
          requirements of the reserves  classification  (proved,  probable) to
          which they are assigned.

     In multi-well pools it may be appropriate to allocate total pool reserves
     between the  developed  and  undeveloped  categories  or to subdivide the
     developed reserves for the pool between developed producing and developed
     non-producing.  This  allocation  should  be  based  on  the  estimator's
     assessment as to the reserves that will be recovered from specific wells,
     facilities  and  completion  intervals  in the pool and their  respective
     development and production status.

     LEVELS OF CERTAINTY FOR REPORTED RESERVES

     The qualitative certainty levels referred to in the definitions above are
     applicable to individual  reserves  entities  (which refers to the lowest
     level at which  reserves  calculations  are  performed)  and to  reported
     reserves  (which  refers to the highest  level sum of  individual  entity
     estimates for which reserves are  presented).  Reported  reserves  should
     target the following levels of certainty under a specific set of economic
     conditions:

     (a)  at  least a 90  percent  probability  that the  quantities  actually
          recovered will equal or exceed the estimated proved reserves; and

     (b)  at  least a 50  percent  probability  that the  quantities  actually
          recovered will equal or exceed the sum of the estimated  proved plus
          probable reserves.

     A  qualitative  measure of the certainty  levels  pertaining to estimates
     prepared for the various  reserves  categories  is desirable to provide a
     clearer understanding of the associated risks and uncertainties. However,
     the majority of reserves  estimates will be prepared using  deterministic
     methods that do not provide a mathematically derived quantitative measure
     of  probability.  In  principle,  there should be no  difference  between
     estimates prepared using probabilistic or deterministic methods.

     Additional  clarification  of certainty  levels  associated with reserves
     estimates and the effect of aggregation is provided in the COGE Handbook.

5.   FORECAST PRICES AND COSTS

     These are  prices  and costs  that are  generally  acceptable  as being a
     reasonable  outlook of the future.  To the extent that there are fixed or
     presently  determinable  future  prices or costs to which we are  legally
     bound by a contractual or other obligation to supply a physical  product,
     including  those for an extension  period of a contract that is likely to
     be  extended,  those  prices  or  costs  shall be  incorporated  into the
     forecast prices.

     The forecast  cost and price  assumptions  include  increases in wellhead
     selling  prices and take into  account  inflation  with respect to future
     operating  and  capital  costs.  Crude oil,  natural  gas and natural gas
     liquids benchmark reference pricing, as at January 1, 2006, inflation and
     exchange rates utilized in the GLJ Report were as follows:

<PAGE>
                                      16


<TABLE>
<CAPTION>
                                       SUMMARY OF PRICING AND INFLATION RATE ASSUMPTIONS
                                                    as of December 31, 2005
                                                   FORECAST PRICES AND COSTS

                                OIL                                         EDMONTON LIQUIDS PRICES
             ---------------------------------------------              ---------------------------------
                          Edmonton
                            Par      Hardisty   Cromer      NATURAL
                WTI        Price      Heavy     Medium        GAS
              Cushing    40(degree) 12(degree) 29.3(degree) AECO Gas                            Pentanes   INFLATION   EXCHANGE
             Oklahoma       API        API        API         Price       Propane    Butane       Plus      RATES(1)    RATE(2)
   Year      ($US/bbl)   ($Cdn/bbl) ($Cdn/bbl) ($Cdn/bbl)  ($Cdn/MMbtu) ($Cdn/bbl) ($Cdn/bbl)  ($Cdn/bbl)    %/Year    ($US/$Cdn)
   ----      ---------   ---------- ---------- ----------  ------------ ---------- ---------- ------------   ------    ----------
<S>             <C>       <C>        <C>        <C>          <C>         <C>         <C>        <C>          <C>         <C>
Forecast
2006            57.00      66.25      33.25       55.75       10.60          42.50     49.00      67.00       2.0         0.85
2007            55.00      64.00      32.75       55.25        9.25          41.00     47.25      65.25       2.0         0.85
2008            51.00      59.25      32.50       51.25        8.00          38.00     43.75      60.50       2.0         0.85
2009            48.00      55.75      32.00       48.25        7.50          35.75     41.25      56.75       2.0         0.85
2010            46.50      54.00      32.00       46.75        7.20          34.50     40.00      55.00       2.0         0.85
2011            45.00      52.25      33.50       45.25        6.90          33.50     38.75      53.25       2.0         0.85
2012            45.00      52.25      33.50       45.25        6.90          33.50     38.75      53.25       2.0         0.85
2013            46.00      53.25      34.00       46.00        7.05          34.00     39.50      54.25       2.0         0.85
2014            46.75      54.25      34.75       47.00        7.20          34.75     40.25      55.25       2.0         0.85
2015            47.75      55.50      35.25       48.00        7.40          35.50     41.00      56.50       2.0         0.85
2016            48.75      56.50      36.00       48.75        7.55          36.25     41.75      57.75       2.0         0.85
Thereafter      (3)        (3)        (3)         (3)         (3)            (3)       (3)        (3)
</TABLE>

Notes:
(1)  Inflation rates for forecasting prices and costs.
(2)  Exchange  rates used to generate the benchmark  reference  prices in this
     table.
(3)  Prices escalate 2.0% per year from 2017

     Weighted  average actual prices  realized for the year ended December 31,
     2005,  were  $8.96/Mcf  for  natural  gas,  $61.11/bbl  for crude oil and
     $73.40/bbl for condensate and $37.69/bbl for natural gas liquids.  Only a
     minor  amount  of our  production  is  characterized  as heavy  oil.  The
     weighted  average  actual price for heavy oil for the year ended December
     31, 2005 has been included in the weighted average actual price for crude
     oil noted above for this same period.

6.   CONSTANT PRICES AND COSTS

     These  are  actual  prices  and  costs  as at the  effective  date of the
     estimation,   held  constant   throughout  the  estimated  lives  of  the
     properties to which the estimate  applies.  To the extent that, there are
     fixed or presently  determinable  future  prices or costs to which we are
     legally bound by a contractual  or other  obligation to supply a physical
     product,  including  those for an extension  period of a contract that is
     likely to be extended,  those prices or costs shall be incorporated  into
     the price for future years.

     The constant  crude oil and natural gas benchmark  reference  pricing and
     the exchange rate utilized in the GLJ Report were as follows:

<PAGE>
                                      17

<TABLE>
<CAPTION>
                                       SUMMARY OF PRICING ASSUMPTIONS
                                           as of December 31, 2004
                                         CONSTANT PRICES AND COSTS

                      OIL                                           EDMONTON LIQUIDS PRICES
   ---------------------------------------------              ----------------------------------
                Edmonton
                  Par                  Cromer       NATURAL
      WTI        Price     LLB Crude   Medium         GAS
    Cushing    40(degree)   Oil at   29.3(degree)   AECO Gas                          Pentanes    EXCHANGE
   Oklahoma       API      Hardesty       API         Price     Propane    Butane       Plus       RATE(1)
   ($US/bbl)   ($Cdn/bbl) ($Cdn/bbl) ($Cdn/bbl)  ($Cdn/MMbtu) ($Cdn/bbl) ($Cdn/bbl)  ($Cdn/bbl)    %/Year
   ---------   ---------- ---------- ----------  ------------ ---------- ----------  ----------    ------
   <C>          <C>       <C>        <C>            <C>        <C>        <C>         <C>          <C>
   61.04        68.27      39.20       51.84          9.71      43.69      50.52       71.67       0.8577
</TABLE>

Note:
(1)  The exchange rate used to generate the benchmark reference prices in this
     table.

7.   FUTURE DEVELOPMENT COSTS

     The  following  table  sets  forth  development  costs  deducted  in  the
     estimation  of our  future  net  revenue  attributable  to  the  reserves
     categories noted below.

<TABLE>
<CAPTION>
                                           Forecast Prices and Costs            Constant Prices and Costs
                                   -----------------------------------------    -------------------------
                                   Proved Reserves      Proved Plus Probable
              Year                      (MM$)                Reserves (MM$)       Proved Reserves (MM$)
              ----                      -----                --------------       ---------------------
<S>                                    <C>                     <C>                          <C>
2006                                    169.8                   199.4                       169.8
2007                                    114.2                   154.5                       112.0
2008                                     68.3                    93.9                        65.7
2009                                     27.4                    61.2                        25.8
2010                                     15.4                    40.2                        14.2
Total: Undiscounted                     487.6                   662.9                       455.7
Total:  Discounted at 10%/year          369.9                   501.5                       360.1
</TABLE>

     We  expect  to fund the  development  costs  of the  reserves  through  a
     combination of cash flow withheld from  distributions,  debt, the sale of
     existing assets and the issuance of Trust Units.

     There can be no  guarantee  that funds will be  available or that we will
     allocate  funding to develop all of the  reserves  attributed  in the GLJ
     Report. Failure to develop those reserves would have a negative impact on
     future cash flow.

     The  interest or other costs of external  funding are not included in the
     reserves and future net revenue  estimates and would reduce  reserves and
     future net revenue to some  degree  depending  upon the  funding  sources
     utilized. We do not anticipate that interest or other funding costs would
     make development of any property uneconomic.

8.   The  Alberta  royalty tax credit  ("ARTC") is included in the  cumulative
     cash flow amounts.  ARTC is based on the program announced  November 1989
     by the Alberta government with modifications effective January 1, 1995.

9.   Estimated  future well  abandonment  costs related to reserves wells have
     been taken into account by GLJ in  determining  the aggregate  future net
     revenue therefrom.

10.  Both the  constant and forecast  price and cost  assumptions  assumed the
     continuance of current laws and regulations.

11.  All factual data  supplied to GLJ was accepted as  represented.  No field
     inspection was conducted.

<PAGE>
                                      18


12.  THE ESTIMATES OF FUTURE NET REVENUE  PRESENTED IN THE TABLES ABOVE DO NOT
     REPRESENT FAIR MARKET VALUE.

RECONCILIATIONS OF CHANGES IN RESERVES AND FUTURE NET REVENUE

The following  table sets forth the  reconciliation  of our net reserves as at
December 31, 2005,  using forecast  price and cost estimates  derived from the
GLJ Report.  Net  reserves as at December 31, 2005 and as at December 31, 2004
include  working  interest  reserves plus royalties  receivable less royalties
payable.

<TABLE>
<CAPTION>
                                                        RECONCILIATION OF
                                                          NET RESERVES
                                                    BY PRINCIPAL PRODUCT TYPE
                                                    FORECAST PRICES AND COSTS

                             LIGHT AND MEDIUM OIL                 HEAVY OIL               CONVENTIONAL NATURAL GAS
                        -----------------------------   ----------------------------    -----------------------------
                                               Net                            Net                              Net
                                              Proved                         Proved                           Proved
                           Net      Net        Plus        Net     Net        Plus        Net       Net        Plus
                        Proved   Probable    Probable   Proved  Probable    Probable    Proved   Probable    Probable
       Factors          (Mbbl)    (Mbbl)      (Mbbl)    (Mbbl)   (Mbbl)      (Mbbl)     (MMcf)    (MMcf)      (MMcf)
       -------          ------    ------      ------    ------   ------      ------     ------    ------      ------
<S>                     <C>        <C>        <C>       <C>        <C>        <C>      <C>         <C>       <C>
December 31, 2004       70,388     20,539     90,981    2,952      782        3,734    485,381    111,014    596,395

 Extensions                397         72        470       41      -23           18     11,523      8,468     19,991
 Improved Recovery(1)    2,849        706      3,554        4        1            5     17,709      2,162     19,871
 Technical Revisions       179       -912       -733       -8      -75          -83      5,378     -5,716       -338
 Discoveries                 0          0          0        0        0            0      3,443      1,095      4,538
 Acquisitions           34,200      6,191     40,390        0        0            0     12,962      2,229     15,191
 Dispositions             -357        -59       -416        0        0            0       -894       -197     -1,091
 Economic Factors          780       -452        328      175       15          190      4,280        433      4,712
 Production             -6,761          0     -6,761     -406        0         -406    -50,281          0    -50,281

December 31, 2005       101,674    26,139    127,813    2,758      699        3,458    489,501    119,488    608,988
</TABLE>

<TABLE>
<CAPTION>
                             NATURAL GAS LIQUIDS                    TOTAL
                        -----------------------------   ----------------------------
                                               Net                            Net
                                              Proved                         Proved
                          Net      Net        Plus        Net     Net        Plus
                        Proved   Probable    Probable   Proved  Probable    Probable
       Factors          (Mbbl)    (Mbbl)      (Mbbl)    (mboe)   (mboe)      (mboe)
       -------          ------    ------      ------    ------   ------      ------
<S>                     <C>         <C>       <C>       <C>       <C>        <C>
December 31, 2004       8,251      1,992     10,243    162,488    41,869     204,357

 Extensions               225        104        329     2,584      1,565       4,149
 Improved Recovery(1)     365         90        455     6,169      1,157       7,326
 Technical Revisions     -201       -263       -465       865     -2,201      -1,336
 Discoveries               42         10         52       616        192         808
 Acquisitions           1,035        178      1,212    37,395      6,739      44,134
 Dispositions             -42         -9        -51      -548       -101        -649
 Economic Factors          24         -9         15     1,691       -374       1,317
 Production            -1,077          0     -1,077    -16,624         0     -16,624

December 31, 2005       8,621      2,093     10,713    194,636    48,846     243,482
</TABLE>

Note:
(1)  Improved recovery includes infill drilling  additions of 2,187 Mbbl light
     and medium oil, 0 Mbbl heavy oil,  13,934  MMcf  natural gas and 189 Mbbl
     NGLs total  proved,  Also  2,890 Mbbl light and medium  oil, 0 Mbbl heavy
     oil,  15,569  MMcf  natural  gas and 262  Mbbl  NGLs  total  proved  plus
     probable.

<PAGE>
                                      19

<TABLE>
<CAPTION>
                                 RECONCILIATION OF CHANGES IN
                           NET PRESENT VALUES OF FUTURE NET REVENUE
                                       DISCOUNTED AT 10%
                                     TOTAL PROVED RESERVES
                                   CONSTANT PRICES AND COSTS

                                                                                  2005
PERIOD AND FACTOR                                                                 (MM$)
-----------------                                                                 -----
<S>                                                                              <C>
Estimated Net Present Value at January 1, 2005                                   2,262.7

     Oil and gas sales during the period net of production costs and royalties(1) (685.9)
     Changes due to prices, production costs and royalties related to
     forecast production(2)                                                      1,654.1
     Development costs during the period(3)                                        251.8
     Changes in forecast development costs(4)                                     (307.7)
     Changes resulting from extensions and improved recovery(5)                    219.2
     Changes resulting from discoveries(5)                                          22.0
     Changes resulting from acquisitions of reserves(5)                            693.1
     Changes resulting from dispositions of reserves(5)                            (14.4)
     Accretion of discount(6)                                                      226.3
     Net change in income taxes(7)                                                     0
     Changes resulting from technical reserves revisions                            64.2
     All other changes                                                             (83.2)

Estimated Net Present Value at End of Period                                     4,302.0
</TABLE>
Notes:
(1)  Actual  revenues  received  (net of the  realized  cash  loss on  hedging
     contracts of $87.6MM) but before  income  taxes,  excluding  interest and
     general and administrative expenses.
(2)  The impact of changes in prices and other economic  factors on future net
     revenue.
(3)  Actual capital expenditures relating to the exploration,  development and
     production of oil and gas reserves.
(4)  The change in forecast  development costs for the properties evaluated at
     the beginning of the period.
(5)  End of  period  net  present  value  of the  related  reserves.  Improved
     Recovery included Infill Drilling.
(6)  Estimated as 10% of the beginning of period net present value.
(7)  As a royalty  trust,  the Trust's  income tax liability is transferred to
     the its Unitholders.


ADDITIONAL INFORMATION RELATING TO RESERVES DATA

PROVED AND PROBABLE UNDEVELOPED RESERVES

Undeveloped  reserves are  attributed by GLJ in accordance  with standards and
procedures  contained in the COGE Handbook.  Proved  undeveloped  reserves are
those  reserves that can be estimated  with a high degree of certainty and are
expected  to  be  recovered  from  known  accumulations  where  a  significant
expenditure  is  required  to render  them  capable  of  production.  Probable
undeveloped  reserves are those reserves that are less certain to be recovered
than proved reserves and are expected to be recovered from known accumulations
where a  significant  expenditure  is  required  to  render  them  capable  of
production.

In some cases it will take us longer than 2 years to develop  these  reserves.
We plan to develop  the  majority  of the proved  undeveloped  reserves in the
reserves  evaluation over the next four years and plan to develop the probable
undeveloped reserves over the next five years.

We manage  development  activities to ensure  facilities and gathering systems
are properly  utilized over the facility life which means  scheduling  capital
over a longer period. We develop assets in a methodical fashion to reduce risk
by  technically  assessing the results of one annual  drilling  program before
embarking on another drilling program.

<PAGE>
                                      20


SIGNIFICANT FACTORS OR UNCERTAINTIES

We have a significant  amount of proved  undeveloped  reserves assigned to the
Dawson gas field in  northeast  British  Columbia and the  Hatton/Horsham  gas
fields in southwest  Saskatchewan.  Sophisticated and expensive  technology is
required for the Dawson wells to produce.  At the current prices,  these wells
are economic; however, should gas prices fall materially, the wells may not be
economic to drill. Similarly, the low rate gas wells in southwest Saskatchewan
may also be uneconomic in a low price environment.

OTHER OIL AND GAS INFORMATION

Our portfolio of properties as at December 31, 2005 includes both unitized and
non-unitized  oil and  natural gas  production.  In  general,  the  properties
contain long life, low decline rate reserves and include  interests in several
major oil and gas fields.

PRINCIPAL PROPERTIES

The following is a description of our principal oil and natural gas properties
as at December  31,  2005.  Reserves  amounts are stated at December 31, 2005,
based on escalated  cost and price  assumptions as evaluated in the GLJ Report
prepared  by GLJ  (see  "Statement  of  Reserves  Data and  Other  Oil and Gas
Information").  Information  in respect of gross and net acres and well counts
are as at December 31, 2005,  and  information in respect of production is for
the year ended December 31, 2005 except where indicated otherwise.  Due to the
fact  that we have  been  active  at  acquiring  additional  interests  in our
principal properties, the working interest share and interest in gross and net
acres and wells as at December  31, 2005 may not  directly  correspond  to the
stated  production for the year which only includes  production since the date
the  interests  were  acquired by us. The estimates of reserves and future net
revenue for individual properties may not reflect the same confidence level as
estimates  of reserves and future net revenue for all  properties,  due to the
effects of aggregation.

All of the  properties  described  below are located in the  Western  Canadian
Sedimentary  Basin and  within the  Canadian  provinces  of British  Columbia,
Alberta or Saskatchewan.  The properties represent 56 percent of the total net
proved plus probable reserves as assigned by GLJ in the GLJ Report.  There are
no other  properties which  individually  account for more than 4.2 percent of
the total net proved  plus  probable  reserves  as  assigned by GLJ in the GLJ
Report.  There  are  no  material  properties  to  which  reserves  have  been
attributed  which are capable of  producing  but which are not  producing  and
there are no material  statutory  or  mandatory  relinquishments,  surrenders,
back-ins or changes in ownership provisions.


<PAGE>
                                      21


                           Net Reserves and Net Production
                     -------------------------------------------
                                    Proved Plus
                                     Probable
                     Production       Proved            Reserves
                       (boe/d)      Reserves (mboe)      (mboe)
                     ----------     -----------         --------
Redwater(1)            3,473           19,072           22,695
Ante Creek             3,107           13,697           17,402
Lougheed               2,550            5,503            7,312
Jenner                 2,406           11,841           14,981
Hatton                 2,285            9,223           10,679
Pouce Coupe            1,828            3,672            4,294
Dawson                 1,757           12,971           17,398
Weyburn Unit           1,559            7,902           10,808
MIPA                   1,475            8,425           10,139
NPCU No. 1(1)          1,347           12,267           13,916
Prestville             1,187            4,522            6,906
Westerose              1,101            1,914            2,328

Note:
(1)  These  properties  were  acquired by us on December 16, 2005.  The quoted
     production  represents  average  daily  rates  during the last 16 days of
     2005.

REDWATER

The Redwater property is located in central Alberta. The property was acquired
by us on December 16, 2005. We are now the operator and own an 84 percent land
interest.  Oil and  solution  gas are both  processed  at an operated  central
facility.  During  the  last  16  days  of  2005  following  the  date  of the
Acquisition,  net production  averaged 3,473 boe/d of oil, gas and natural gas
liquids from 383 net wells.  GLJ  assigned net proved  reserves of 19,072 mboe
and net proved plus  probable  reserves of 22,695 of oil,  gas and natural gas
liquids  to this  area,  or 9.3  percent  of total net  proved  plus  probable
reserves.

ANTE CREEK

The Ante Creek property is located in northwest  Alberta.  We are the operator
and own an average land  interest of 93 percent.  Oil  production is processed
through two operated  facilities while the gas is routed through a third party
plant.  During 2005, net production from the area averaged 3,107 boe/d of oil,
gas and natural gas liquids from 119 net wells. During 2005, 14 new wells were
drilled.  GLJ assigned net proved  reserves of 13,697 mboe and net proved plus
probable  reserves of 17,402 mboe of oil,  gas and natural gas liquids to this
area, or 7.1 percent of total net proved plus probable reserves.

LOUGHEED

The  Lougheed  property  is  located  in  southeast  Saskatchewan.  We are the
operator and own an average land interest of 79 percent. Production is handled
by an operated  battery and gas plant.  During 2005, net  production  from the
area  averaged  2,550 boe/d of oil and natural gas liquids from 138 net wells.
During 2005,  8 new wells were  drilled.  GLJ assigned net proved  reserves of
5,503  mboe and net proved  plus  probable  reserves  of 7,312 mboe of oil and
natural  gas  liquids to this area,  or 3.0 per cent of total net proved  plus
probable reserves.

JENNER

The Jenner property is located in southeast  Alberta.  We are the operator and
own an  average  land  interest  of 88 per cent.  We  operate  all 4 major gas
compression  and  dehydration   facilities  in  the  area.  During  2005,  net
production  from the area  average  2,406  boe/d of  natural  gas from 694 net
wells.  During  2005,  94 new wells  were  drilled.  GLJ  assigned  net proved
reserves of 11,841 mboe and net proved plus

<PAGE>
                                      22


probable  reserves of 14,981 mboe of oil and natural gas to this area,  or 6.2
per cent of the net proved plus probable reserves.

HATTON

The  Hatton  property  is  located  in  southwest  Saskatchewan.  There  is  a
combination of operated and non operated acreage with an average land interest
of  44  per  cent.  The  operated  production  flows  through  three  operated
compression and dehydration  facilities where our working interest ranges from
50 to 100 per cent.  During 2005, net production  from the area averaged 2,285
boe/d of  natural  gas from 394 net  wells.  During  2005,  61 new wells  were
drilled.  GLJ assigned  net proved  reserves of 9,223 mboe and net proved plus
probable  reserves of 10,679 mboe of natural gas to this area, or 4.4 per cent
of total net proved plus probable reserves.

POUCE COUPE

The Pouce Coupe property is located in northwest Alberta,  We are the operator
and own an average  land  interest of 74 per cent.  The sweet gas is processed
through  an  operated  gas  plant  and the  sour gas  flows  to a third  party
processing  plant.  During 2005, net  production  from the area averaged 1,828
boe/d of oil,  natural gas and natural gas liquids  from 44 net wells.  During
2005, 3 new wells were drilled. GLJ assigned net proved reserves of 3,672 mboe
and net proved plus  probable  reserves of 4,294 mboe of oil,  natural gas and
natural  gas  liquids to this area,  or 1.8 per cent of total net proved  plus
probable reserves.

DAWSON

The Dawson  property  is located in  northeast  British  Columbia.  We are the
operator  and own an average land  interest of 91 percent.  We operate a large
area compression facility where the natural gas and liquids are then sent to a
third party operated facility for sweetening. During 2005, net production from
the area  averaged  1,757 boe/d of natural gas and natural gas liquids from 53
net wells.  During  2005,  7 new wells were  drilled.  GLJ assigned net proved
reserves of 12,971 mboe and net proved plus  probable  reserves of 17,398 mboe
of natural gas and natural gas liquids to this area,  or 7.1 per cent of total
net proved plus probable reserves.

WEYBURN UNIT

The Weyburn  unit is located in  southeast  Saskatchewan.  EnCana  Corporation
operates the unit and we have a working  interest of 6.5 per cent. The unit is
currently  undergoing a CO2 flood for enhanced oil  recovery.  During 2005 net
production  from the unit averaged  1,559 boe/d of oil and natural gas liquids
from 58 net wells.  During 2005, 28 new wells were  drilled.  GLJ assigned net
proved reserves of 7,902 mboe and net proved plus probable  reserves of 10,808
mboe of oil and natural gas to this area,  or 4.4 per cent of total net proved
plus probable reserves.

MIPA

The MIPA property is located in central Alberta. We are the operator and own a
100 percent  interest in  production  and reserves in the Cardium zone. We own
and operate all batteries and  facilities but the solution gas is processed by
a third party.  During 2005, net production from the area averaged 1,475 boe/d
of oil,  gas and natural gas liquids  from 232 net wells.  During  2005, 7 new
wells were  drilled.  GLJ assigned  net proved  reserves of 8,425 mboe and net
proved plus probable  reserves of 10,139 mboe of oil,  natural gas and natural
gas liquids to this area,  or 4.2 per cent of total net proved  plus  probable
reserves.

<PAGE>
                                      23


NPCU NO. 1

The North  Pembina  Cardium  Unit No. 1 is  located in  central  Alberta.  The
property was acquired by us on December 16, 2005.  We are the operator and own
a 45.57%  percent  interest in the unit.  Production is processed  through two
operated oil treatment  facilities and one operated solution gas plant. During
the last 16 days of 2005, net production from the area averaged 1,347 boe/d of
oil,  natural gas and natural gas liquids from 242 net wells. GLJ assigned net
proved reserves of 12,267 mboe and net proved plus probable reserves of 13,916
mboe of oil,  natural gas and natural gas liquids to this area, or 5.7 percent
of total net proved plus probable reserves.

PRESTVILLE

The Prestville  property is located in northwest Alberta.  We are the operator
and own a 100 percent  working  interest in production  and  reserves.  Oil is
processed at an operated battery while the solution gas flows to a third party
processor.  During 2005, net production  from the area averaged 1,187 boe/d of
oil, natural gas and natural gas liquids from 11 net wells. During 2005, 6 new
wells were  drilled.  GLJ assigned  net proved  reserves of 4,522 mboe and net
proved plus  probable  reserves of 6,906 mboe of oil,  natural gas and natural
gas liquids to this area,  or 2.8  percent of total net proved  plus  probable
reserves.

WESTEROSE

The Westerose property is located in central Alberta.  We have an average land
interest of 17 per cent. A variety of companies  operate this property and the
production is handled through an assortment of non operated facilities. During
2005 net production  from the area averaged 1,101 boe/d of natural gas from 26
net wells.  GLJ assigned net proved reserves of 1,914 mboe and net proved plus
probable  reserves of 2,328 mboe of natural gas to this area,  or 1.0 per cent
of total net proved plus probable reserves.

OIL AND GAS WELLS

The following  table sets forth the number and status of wells in which we had
a working interest as at December 31, 2005.

<TABLE>
<CAPTION>
                                     Oil Wells                                Natural Gas Wells
                      -----------------------------------------    ---------------------------------------
                           Producing            Non-Producing            Producing           Non-Producing
                           ---------            -------------            ---------           -------------
                       Gross       Net        Gross        Net       Gross        Net      Gross       Net
                       -----       ---        -----        ---       -----        ---      -----       ---
<S>                    <C>       <C>         <C>           <C>      <C>        <C>         <C>         <C>
Alberta                3,972     1,450       1,009         161      3,633      1,633         168        30
British Columbia         126         3          24           0        233         59          37        10
Saskatchewan           1,905       681         269          79      4,956        705          50        22
                       -----     -----       -----         ---      -----      -----         ---        --
Total                  6,003     2,134       1,302         240      8,812      2,397         255        62
                       =====     =====       =====         ===      =====      =====         ===        ==
</TABLE>

<PAGE>
                                      24


PROPERTIES WITH NO ATTRIBUTABLE RESERVES

The following table sets out our undeveloped  land holdings as at December 31,
2005.

                                 Undeveloped Acres
                                --------------------
                                Gross           Net
                                -----           ---

Alberta                         585,876      279,340
British Columbia                 85,183       56,179
Saskatchewan                    245,177       92,827
Northwest Territories           276,262       27,881
                              ---------      -------
Total                         1,192,499      456,227
                              =========      =======

We currently have no material work  commitments on these lands. We expect that
approximately 56,000 net acres of our undeveloped land holdings will expire by
December 31, 2006.


FORWARD CONTRACTS

We are  exposed to market  risks  resulting  from  fluctuations  in  commodity
prices,  foreign  exchange  rates and interest  rates in the normal  course of
operations.  A  variety  of  derivative  instruments  are used to  reduce  our
exposure to  fluctuations  in commodity  prices,  foreign  exchange  rates and
interest  rates.  We are  exposed  to losses in the  event of  default  by the
counterparties  to  these  derivative  instruments.  We  manage  this  risk by
diversifying  our derivative  portfolio  among a number of  financially  sound
counterparties.  For  information in relation to marketing  arrangements,  see
"Other Oil and Gas Information - Marketing Arrangements".

We have a hedging  program under which  financial  and physical  hedges can be
entered  into in respect of  commodity  prices and foreign  currency  exchange
rates.  The program permits hedging of up to 70 percent of our oil and natural
gas  liquids  production  for up to 12 months  and up to 35 percent of oil and
natural  gas  liquids  production  for the period  commencing  one year in the
future for a maximum of 12 months.  With respect to natural gas  hedging,  the
program  permits the hedging of up to 70 percent of our natural gas production
for up to 24 months and up to 35 percent of natural gas  production for the 36
month period thereafter (years three to five in the future).  The above limits
are  restricted to a maximum of 50 percent on a boe basis for up to 12 months,
up to 25 percent on a boe basis for the 12 month period  thereafter  (year two
in the  future)  and up to 15 percent  on a boe basis for the 36 month  period
thereafter  (years  three to five in the  future).  These hedge  limits can be
changed upon approval by the Board of Directors.

A summary of financial and physical contracts in respect of hedging activities
can be found in Note 9  "Financial  Instruments"  to our audited  consolidated
financial  statements  for the year  ended  December  31,  2005 and  under the
heading  "Risk  Management  and  Hedging"  in our  management  discussion  and
analysis and results of operations  for the year ended December 31, 2005 which
have  been  filed  on SEDAR  at  www.sedar.com,  both  sections  of which  are
incorporated in this Annual Information Form by reference.

<PAGE>
                                      25


ADDITIONAL INFORMATION CONCERNING ABANDONMENT AND RECLAMATION COSTS

The following table sets forth information  respecting future  abandonment and
reclamation costs for surface leases, wells, facilities and pipelines which we
expect to incur for the periods indicated.

<TABLE>
<CAPTION>
                                       Abandonment and Reclamation      Abandonment and Reclamation
                                         Costs escalated at 2.0%          Costs escalated at 2.0%
                                              Undiscounted                   Discounted at 10%
                                                  ($MM)                            ($MM)
                                       ---------------------------      ---------------------------
<S>                                              <C>                               <C>
Total as at December 31, 2005                    603.4                             73.7
Anticipated to be paid in 2006                     2.3                              2.1
Anticipated to be paid in 2007                     2.7                              2.2
Anticipated to be paid in 2008                     2.4                              1.8
</TABLE>

We will be liable for our share of ongoing  environmental  obligations and for
the ultimate  reclamation of the properties  held by us upon  abandonment.  We
estimate  that we have  5,619 net wells  which are  subject  to  environmental
reclamation obligations.  Ongoing environmental obligations are expected to be
funded out of cash flow.

We have a reclamation fund to pay future asset retirement  obligations  costs.
We  currently   estimate  that  the  future   environmental   and  reclamation
obligations in respect of our properties will be approximately  $603.4 million
escalated at 2 percent per year (reflected in the 2005  financials  statements
as an asset retirement  obligation of $165.1 million  calculated by escalating
costs at 2.0  percent  per  year  and  discounting  at a  blended  rate of 5.6
percent).  The Board of Directors  of ARC  Resources  has  approved  voluntary
contributions  over a twenty  year  period  that  results  in  minimum  annual
contributions of $6.0 million ($6.0 million in 2004) based on properties owned
as at December 31, 2005.  During 2005, $4.6 million ($3.1 million for 2004) of
actual expenditures were charged against the reclamation fund resulting in net
contributions for the year of $2.2 million ($4.1 million in 2004).

In  addition  the  Trust  has  committed  to a  restricted  reclamation  trust
associated with the Redwater property acquired in the Acquisition  pursuant to
which ARC Resources  has agreed to  contribute  to such trust certain  minimum
amounts,  totalling  approximately $110 million over a 50 year period, to fund
future  environmental  and reclamation  obligations in respect of the Redwater
properties,  or to expend certain minimum amounts  towards  discharging  these
obligations.  The restricted  contribution  commences in 2006 for $6.1 million
and continues at a declining rate through 2055.

We estimate  the costs to abandon  and  reclaim all our shut in and  producing
wells,  facilities,  gas  plants,  pipelines,  batteries  and  satellites.  No
estimate of salvage value is netted against the estimated  cost. Our model for
estimating  the  amount  and  timing of  future  abandonment  and  reclamation
expenditures  was created on an operating area level.  Estimated  expenditures
for each  operating  area are  based on the  Alberta  Energy  Utilities  Board
methodology  which  details  the  cost of  abandonment  and  reclamation  in 8
specific geographic regions. Each region was assigned an average cost per well
to abandon and reclaim the wells in that area.

Abandonment and  reclamation  costs have been estimated over a 61 year period.
Facility  reclamation costs are scheduled to be incurred in the year following
the end of the reserves life of its associated reserve.

The  additional  liability  associated  with well,  pipelines  and  facilities
reclamation  costs  which were not  deducted by GLJ in  estimating  future net
revenue  in the GLJ  Report are  $394.4  million  (escalating  costs at 2% and
undiscounted)  and $38.7  million  (escalating  costs at 2% and  discounted at
10%). Only the abandonment  costs associated with reserves wells were deducted
by GLJ in estimating future net revenue.

<PAGE>
                                      26


TAX HORIZON

As a  result  of  our  tax  efficient  structure,  annual  taxable  income  is
transferred  from our  operating  entities  to the Trust and from the Trust to
Unitholders.  This is  primarily  accomplished  through the  deduction  by our
operating  entities of the Royalties on underlying  oil and gas properties and
the  deduction  of  interest  on the Long  Term  Notes.  Therefore,  it can be
expected that no income tax  liability  would be incurred by us for as long as
we maintain this  organizational  tax  structure.  However,  annual  operating
income retained to pay a portion of capital expenditures or used to repay debt
may result in income tax liabilities of ARC Resources from time to time.

CAPITAL EXPENDITURES

The following tables summarize capital expenditures (net of incentives and net
of certain  proceeds  and  including  capitalized  general and  administrative
expenses) related to our activities for the year ended December 31, 2005:

                                     2005
                                      $M
                                   -----------
Corporate acquisition costs(1)      $504,996
Property acquisition costs(2)
     Proved properties                91,253
     Undeveloped properties               33
Exploration costs(3)                  43,987
Development costs(4)                 221,137
Corporate costs                        3,710
                                   -----------
Total                               $865,116
                                   ===========
Notes:
(1)  Represents total consideration for the transactions,  including fees, but
     is prior to the related  future income tax  liability,  asset  retirement
     obligation and working capital assumed on acquisition.
(2)  Represents acquisition costs net of dispositions and property swaps.
(3)  Costs of land acquired,  geological and geophysical capital  expenditures
     and drilling costs for 2005 exploration wells drilled.
(4)  Development and facilities capital expenditures.

EXPLORATION AND DEVELOPMENT ACTIVITIES

The following  table sets forth the gross and net  exploratory and development
wells that we participated in during the year ended December 31, 2005:

<TABLE>
<CAPTION>
                            EXploratory Wells       Development Wells             Total
                            ----------------       -------------------      ----------------
                            Gross        Net       Gross           Net      Gross        Net
                            -----        ---       -----           ---      -----        ---
<S>                         <C>          <C>       <C>           <C>        <C>        <C>
Light and Medium Oil            6        6.0         109          45.5        115       51.5
Natural Gas                    46        6.8         275         135.9        321      142.7
Service                         0        0.0           5           1.5          5        1.5
Dry                             4        1.5           3           0.7          7        2.2
                            -----       ----       -----         -----      -----      -----
Total:                         56       14.3         392         183.6        448      197.9
                            =====       ====       =====         =====      =====      =====
</TABLE>

We have an extensive  capital program of $340 MM planned for 2006. The primary
components of our program are as follows.

Our planned $38.4 MM program in Dawson includes the drilling of 7 vertical and
three  horizontal  development and delineation  wells. In addition to drilling
activities,  capital  will  also  be  devoted  to  the  construction  of a new
compression facility.

<PAGE>
                                      27


In Ante Creek,  our planned $31 MM capital program includes the drilling of 10
development  wells, four exploration  wells,  water injection  conversions and
waterflood facility upgrades.

In Delburne,  we plan to drill 50 shallow wells and install new facilities and
compression as part of the Natural Gas from Coal program.  The area capital of
$32.1 MM also plans to include the drilling of four Viking infill wells

In the  Jenner  and  Crane  Lake  areas of  Southeast  Alberta  and  Southwest
Saskatchewan,  we plan to drill 150 gross shallow gas wells at a cost of $20.7
MM.

PRODUCTION ESTIMATES

The following  table sets out the volume of our  production  estimated for the
year ended  December 31, 2006 which is reflected in the estimate of future net
revenue  disclosed in the tables  contained under  "Statement of Reserves Data
and Other Oil and Gas Information - Disclosure of Reserves Data".

<TABLE>
<CAPTION>
                                 Light and                                               Natural Gas
                                 Medium Oil        Heavy Oil         Natural Gas           Liquids             Boe
                                  (bbls/d)         (bbls/d)             (Mcfpd)            (bbls/d)         (boe/d)
                             ---------------   --------------    ------------------    --------------  ---------------
                              Gross      Net   Gross      Net      Gross        Net    Gross      Net   Gross      Net
<S>                          <C>      <C>      <C>      <C>      <C>        <C>        <C>      <C>    <C>      <C>
Proved Producing             25,831   21,893     996      996    164,352    133,198    3,793    2,725  58,011   47,814
Proved Developed Non-
Producing                       590      480       0        0      2,884      2,158      127       95   1,198      935
Proved Undeveloped            1,314    1,134       5        4      6,170      4,751      156      105   2,503    2,034
                             ------   ------   -----    -----    -------    -------    -----    -----  ------   ------
Total Proved                 27,735   23,507   1,001      999    173,406    140,107    4,075    2,925  61,712   50,783
Total Probable                  669      533      37       34      5,203      3,941      127       89   1,700    1,314
                             ------   ------   -----    -----    -------    -------    -----    -----  ------   ------
Total Proved Plus
Probable                     28,404   24,041   1,038    1,033    178,609    144,048    4,202    3,015  63,412   52,097
                             ======   ======   =====    =====    =======    =======    =====    =====  ======   ======
</TABLE>


<PAGE>
                                      28


PRODUCTION HISTORY

The  following  tables  summarize  certain   information  in  respect  of  our
production,  product prices received,  royalties paid,  operating expenses and
resulting netback for the periods indicated below:

<TABLE>
<CAPTION>
                                                               Quarter Ended
                                                                   2005
                                               --------------------------------------------   Year Ended
(6:1)                                          Mar. 31      June 30    Sept. 30     Dec. 31        2005
                                               -------      -------    --------     -------        ----
<S>                                             <C>          <C>         <C>         <C>         <C>
Average Daily Production(1)
  Light and Medium Crude Oil (bbl/d)            21,293       22,046      23,513      25,534      23,282
  Gas (MMcfpd)                                   176.1        173.1       168.2       177.9       173.8
  NGLs (bbl/d)                                   4,072        3,962       4,047       3,943       4,005
  Combined (boe/d)                              55,410       54,860      55,592      59,120      56,254

Average Net Production Prices Received
  Light and Medium Crude Oil ($/bbl)             53.63        58.37       69.37       62.12       61.11
  Gas ($/Mcf)                                     7.20         7.42        9.08       12.05        8.96
  NGLs ($/bbl)                                   46.57        46.13       50.42       56.53       49.91
  Combined ($/boe)                               47.74        50.40       60.66       67.16       56.75

Royalties Paid
  Light and Medium Crude Oil ($/bbl)              9.61        11.56       13.95       11.07       11.58
  Gas ($/Mcf)                                     1.34         1.53        1.98        2.55        1.85
  NGLs ($/bbl)                                   12.56        11.99       12.20       15.99       13.18
  Combined ($/boe)                                8.99        10.34       12.77       13.51       11.46

Operating Expenses (2)(3)
  Light and Medium Crude Oil ($/bbl)              9.19         9.46        8.69        8.41        8.62
  Gas ($/Mcf)                                     0.64         1.01        0.99        1.08        0.98
  NGLs ($/bbl)                                    5.69         4.84        5.67        4.24        4.69
  Combined ($/boe)                                6.10         7.35        7.07        7.16        6.93

Transportation Paid
  Light and Medium Crude Oil ($/bbl)              0.17         0.17        0.09        0.09        0.13
  Gas ($/Mcf)                                     0.21         0.22        0.21        0.20        0.21
  NGLs ($/bbl)                                      --           --          --          --          --
  Combined ($/boe)                                0.72         0.76        0.66        0.65        0.70

(Gain)/Loss on Commodity and Foreign
Exchange Contracts
  Light and Medium Crude Oil ($/bbl)              7.27        11.64        9.30        7.32        8.83
  Gas ($/Mcf)                                    (0.45)        0.25        0.42        0.56        0.20
  NGLs ($/bbl)                                      --           --          --          --          --
  Combined ($/boe)                                1.47         5.46        5.20        4.86        4.26

Netback Received(4)
  Light and Medium Crude Oil ($/bbl)(5)          27.39        25.54       37.34       35.24       31.95
  Gas ($/Mcf)                                     5.46         4.41        5.48        7.66        5.72
  NGLs ($/bbl)                                   28.32        29.30       32.55       36.30       32.04
  Combined ($/boe)                               30.46        26.49       34.96       40.98       33.40
</TABLE>
Notes:
(1)  Before deduction of royalties.
(2)  Operating  expenses are composed of direct costs incurred to operate both
     oil and gas wells. A number of  assumptions  have been made in allocating
     these costs between oil, natural gas and natural gas liquids production.
(3)  Operating  recoveries  associated with operated  properties were excluded
     from  operating  costs and  accounted  for as a reduction  to general and
     administrative costs.
(4)  Netbacks  are  calculated  by  subtracting  royalties,  operating  costs,
     transportation  costs, and losses/gains on commodity and foreign exchange
     contracts from revenues.

<PAGE>
                                      29


(5)  Heavy oil net backs have been included in light/medium  oil netbacks,  as
     only a minor amount of our production comes from heavy oil.

No  property  accounts  for more than 7% percent of the  production  disclosed
above.  For more  information,  see "Other Oil and Gas Information - Principal
Properties".

MARKETING ARRANGEMENTS

NATURAL GAS

During 2005, we continued our  marketing  strategy of increasing  the level of
direct   control  and   diversification   of  marketing   and   transportation
arrangements for our natural gas production.

The average  natural  gas price we  received  during 2005 was $8.96 per Mcf as
compared to $6.78 per Mcf for 2004.  This price was achieved  with a portfolio
mix that on average  through the year received AECO index based pricing for 66
percent,  aggregator netback prices for 24 percent,  and Chicago Index Pricing
for 10 percent of total production.

To manage natural gas price  volatility  and to stabilize the revenue  stream,
our natural gas portfolio is directed towards maintaining balanced exposure to
U.S. and Canadian markets with market  sensitive and hedgeable  pricing terms,
as  well  as  aggregator  netback  arrangements.  We  also  strive  for a high
utilization of contracted pipeline and processing capacity.

CRUDE OIL AND NATURAL GAS LIQUIDS

Our liquids production in 2005 was comprised of approximately 43 percent light
quality crude oil (greater than  35(degree)  API), 38 percent  medium  quality
crude oil  (25(degree)  to 35(degree)  API),  four percent heavy quality crude
(less than 25(degree) API), five percent condensate and 10 percent natural gas
liquids. During 2005, our average sales prices were $61.11 per bbl for oil and
$73.40 per bbl for condensate and $37.69 per bbl of natural gas liquids; these
prices compare to 2004 prices of $47.03 per bbl for oil and $39.31 per bbl for
condensate  and $38.80 per bbl for natural gas liquids.  Our crude oil is sold
under contracts of varying terms of up to one year,  based on market sensitive
pricing  terms.  Natural  gas  liquids  are sold  under  annual  arrangements.
Industry  pricing  benchmarks  for  crude  oil and  natural  gas  liquids  are
continuously monitored to ensure optimal netbacks.

ACQUISITIONS AND DISPOSITIONS

We completed property acquisitions,  net of dispositions,  of $91.3 million in
2005. We also completed two corporate  acquisitions for total consideration of
$505.0 million resulting in total acquisitions, net of dispositions, of $596.3
million in the year.

                        SHARE CAPITAL OF ARC RESOURCES

COMMON SHARES

ARC Resources has authorized for issuance an unlimited number of common shares
of which 100 common shares are issued and  outstanding  and held by the Trust.
The  voting  of such  shares is  delegated  to ARC  Resources  under the Trust
Indenture.  The holders of common  shares are entitled to notice of, to attend
and to one vote per  share  held at any  meeting  of the  shareholders  of ARC
Resources;  to receive dividends as and when declared by Board of Directors of
ARC  Resources  on  the  common  shares  as a  class,  and  subject  to  prior
satisfaction of all preferential rights to dividends attached to all shares of
other classes; and in the event of any liquidation,  dissolution or winding-up
of ARC Resources,  whether

<PAGE>
                                      30


voluntary  or  involuntary,  or any other  distribution  of the  assets of ARC
Resources  among its  shareholders  for the purpose of winding-up its affairs,
and  subject to prior  satisfaction  of all  preferential  rights to return of
capital on  dissolution  attached to all shares of other  classes of shares of
ARC Resources ranking in priority to the common shares in respect of return of
capital on  dissolution,  to share  rateably,  together with the shares of any
other class of shares of ARC Resources  ranking equally with the common shares
in  respect  of  return  of  capital  on  dissolution,  in such  assets of ARC
Resources as are available for distribution.

EXCHANGEABLE SHARES

ARC  Resources  is  authorized  to issue an unlimited  number of  Exchangeable
Shares of which,  as at December 31, 2005,  1,594,396  were  outstanding.  The
Exchangeable  Shares  rank prior to the common  shares of ARC  Resources,  the
second  preferred  shares of ARC Resources and any other shares ranking junior
to the  Exchangeable  Shares with respect to the payment of dividends  and the
distribution  of  assets  in the  event  of the  liquidation,  dissolution  or
winding-up of ARC Resources;  provided that  notwithstanding  such ranking ARC
Resources shall not be restricted in any way from repaying indebtedness of ARC
Resources to the Trust from time to time. The  Exchangeable  Share  provisions
have been filed on SEDAR at WWW.SEDAR.COM.

The  Exchangeable  Shares  provide  holders with a security  having  economic,
ownership  and voting  rights which are  substantially  equivalent to those of
Trust  Units.  As at December 31, 2005 the  Exchange  Ratio was 1.83997  Trust
Units per Exchangeable Share.  Holders of Exchangeable Shares will not receive
cash distributions, rather the Exchangeable Shares are maintained economically
equivalent  to the Trust Units by the  progressive  increase  in the  Exchange
Ratio  to  reflect  distributions  paid  by  the  Trust  to  Unitholders.  The
Exchangeable  Shares  are  provided  equivalent  voting  rights  as  those  of
Unitholders  through an agreement (the Exchangeable  Share Voting and Exchange
Trust  Agreement)  pursuant  to which the holders of  Exchangeable  Shares can
direct  the  Trustee  to vote at  meetings  of  Unitholders.  The  holders  of
Exchangeable  Shares are further  assured of the delivery of Trust Units by us
in satisfaction  of the  obligations of ARC Resources  under the  Exchangeable
Share terms through the  provisions  of another  agreement  (the  Exchangeable
Share Support Agreement). Copies of the Exchangeable Share Voting and Exchange
Trust Agreement and the Exchangeable  Share Support  Agreement have been filed
on SEDAR at www.sedar.com.

Computershare  Trust  Company  of Canada  acts as the  transfer  agent for the
Exchangeable Shares.

Holders of Exchangeable  Shares are entitled to receive,  as and when declared
by the  Board  of  Directors  in its  sole  discretion,  from  time  to  time,
cumulative  preferential  cash  dividends  in an amount per share equal to the
Exchange  Ratio on the  preceding  business day  multiplied by the fair market
value of a Trust Unit as at the  preceding  business  day  (determined  on the
basis of the  weighted  average  price of the Trust Unit on the TSX for the 10
trading days preceding that date). It is not  anticipated  that dividends will
be declared or paid on the Exchangeable Shares, however the Board of Directors
has the right in its sole  discretion to do so, and if so, the Exchange  Ratio
would be reduced accordingly to reflect such dividends.

ARC Resources will not,  without  obtaining the approval of the holders of the
Exchangeable Shares:

     (a)  pay any  dividend  on the  common  shares of ARC  Resources,  second
          preferred shares of ARC Resources or any other shares ranking junior
          to the Exchangeable  Shares,  other than the stock dividends payable
          in common shares of ARC  Resources or any such other shares  ranking
          junior to the Exchangeable Shares;

<PAGE>
                                      31


     (b)  redeem,  purchase or make any capital distribution in respect of the
          common  shares  of ARC  Resources,  second  preferred  shares of ARC
          Resources or any other  shares  ranking  junior to the  Exchangeable
          Shares;

     (c)  redeem or purchase any other shares of ARC Resources ranking equally
          with  respect to the  payment  of  dividends  or on any  liquidation
          distribution; or

     (d)  issue any shares, other than Exchangeable  Shares,  second preferred
          shares of ARC  Resources or common  shares of ARC  Resources,  which
          rank superior to the Exchangeable Shares with respect to the payment
          of dividends or on any liquidation distribution.

Notwithstanding the foregoing, the restrictions in paragraphs (a), (b) and (c)
above shall only be  applicable  if dividends  which have been declared on the
outstanding Exchangeable Shares have not been paid in full.

The  Exchangeable  Share  Provisions  entitle  the  holder  to  exchange  each
Exchangeable  Share at any time into the  number of Trust  Units  equal to the
Exchange  Ratio then in effect.  The Exchange Ratio is determined by reference
to the  distributions  paid on Trust  Units in a given  month and the  current
market price of the Trust Units.

SECOND PREFERRED SHARES

ARC  Resources  also has  authorized an unlimited  number of Second  Preferred
Shares  which  may at any time or from  time to time be  issued in one or more
series.  Before any shares of a  particular  series are  issued,  the Board of
Directors of ARC Resources shall, by resolution, fix the number of shares that
will form such series and shall, subject to the limitations set out herein, by
resolution  fix  the  designation,   rights,   privileges,   restrictions  and
conditions to be attached to the Second Preferred  Shares of such series.  The
Second  Preferred  Shares of each series  shall rank  behind the  Exchangeable
Shares and on a parity with the Second  Preferred Shares of every other series
with  respect  to  accumulated  dividends  and return of  capital.  The Second
Preferred  Shares are entitled to a preference over the Common Shares and over
any other  shares of ARC  Resources  ranking  junior to the  Second  Preferred
Shares  with  respect  to  priority  in the  payment of  dividends  and in the
distribution  of  assets  in the  event  of the  liquidation,  dissolution  or
winding-up of ARC Resources,  whether  voluntary or involuntary,  or any other
distribution  of the assets of ARC Resources  among its  shareholders  for the
purpose of winding-up its affairs.  As at the date hereof, no Second Preferred
Shares have been issued or are outstanding.

                  OTHER INFORMATION RELATING TO OUR BUSINESS

BORROWING

We borrow funds from time to time to finance the purchase of  properties,  for
capital  expenditures  or for other  financial  obligations or expenditures in
respect of properties  held by us or for working capital  purposes.  We have a
policy  relating  to  borrowing  which  requires  a  quarterly  assessment  by
management,  subject to review by the Board of Directors of ARC Resources,  of
the  appropriateness of borrowing levels. We have granted security in priority
to the Royalties to secure the loan of such funds.

Debt  service  charges  on  borrowed  funds  attributable  to our  properties,
including  funds  borrowed  by our  subsidiaries  from us, will be deducted in
computing royalty income. The debt repayment will be scheduled to minimize any
income tax payable by ARC Resources.

<PAGE>
                                      32


At December 31, 2005, we had revolving credit facilities to a combined maximum
of $950 million  including US $230 million of senior secured notes at December
31, 2005. The credit  facilities  and senior secured notes contain  provisions
which  restrict  the ability of ARC  Resources to pay  Royalties  and interest
under the Long Term Notes to us and  thereby  may  restrict  distributions  to
Unitholders,  in the event of the  occurrence  of  certain  events of  default
including a borrowing  base short fall.  The revolving  credit  facilities are
borrowing base and have a 364 day  extendable  period and a two year term. For
more  information,  reference is made to note 6 of our Consolidated  Financial
Statements  which are  incorporated  by reference  in this Annual  Information
Form.

RESTRICTION ON RESALE AGREEMENTS

In  connection  with the  internalization  transaction  and in order to ensure
continuity  of  management  and  key  individuals,   we  entered  into  escrow
agreements  with certain  holders of ARML shares  dated  August 28,  2002.  On
August 28, 2002,  9,013 Trust Units and  2,008,699  ARML  exchangeable  shares
(1,735,221  Exchangeable  Shares  following  the  exchange  May 16, 2003) were
placed into escrow. The escrow agreements  commenced August 28, 2002 and under
certain of the escrow  agreements,  the  original  securities  deposited  into
escrow  were  releasable  on each of August 29,  2003  through  2007 and under
certain other of the escrow agreements were releasable on each of August 29 of
2003 through 2005. On August 29, 2005, the escrow agreements which had not yet
expired were terminated. While it was determined not to enter into replacement
agreements in respect of all of the securities  which remained in escrow prior
to the  termination  of the  escrow  agreements,  ARC  Resources  entered  new
agreements  in  respect  of an  aggregate  88,692o  Trust  Units  and  335,642
Exchangeable  Shares  (including those securities held by certain officers and
directors of ARC Resources  which were  formerly  held in escrow)  pursuant to
which the holders of such  securities  have agreed to  restrictions  on resale
which are  substantially  similar to those contained in the escrow  agreements
which were  terminated.  Pursuant to these  restriction on resale,  50% of the
securities will be released on each of August 29, 2006 and August 29, 2007.

The following table sets forth the number and percentage of Trust Units and
Exchangeable Shares, which to our knowledge, are subject to restrictions on
resale as at the date hereof.

                        TRUST UNITS AND EXCHANGEABLE SHARES

                                  Number Subject
      Designation of Class     to Resale Restrictions      Percentage of Class
    ------------------------- -------------------------- -----------------------
    Trust Units                        88,692                     0.04%
    Exchangeable Shares                335,642                   21.05%

RETENTION PAYMENTS

As a condition of the  internalization  transaction,  ARML declared  retention
payments to the Chief Executive  Officer and the five  Vice-Presidents  of ARC
Resources  as at August 28, 2002.  ARML and ARC  Resources  were  subsequently
amalgamated  and  accordingly ARC Resources is responsible for these retention
payments.  This payment was to be made in equal  increments of an aggregate of
$1,000,000  per year  for  five  years  but  only if the  individual  remained
employed by ARC  Resources or another  affiliate of the Trust.  The  retention
payments were funded by an effective reduction in the purchase price resulting
in the existing holders of ARML shares  effectively paying for this management
retention program.

<PAGE>
                                      33


                                OUR INFORMATION

TRUST UNITS

A maximum  of  650,000,000  Trust  Units have been  created  and may be issued
pursuant to the Trust  Indenture.  The Trust Units  represent  equal undivided
beneficial  interests  in the  Trust.  All Trust  Units  share  equally in all
distributions  made by us and all Trust  Units carry  equal  voting  rights at
meetings of Unitholders. No Unitholder will be liable to pay any further calls
or  assessments  in respect of the Trust  Units.  No  conversion,  retraction,
redemption or pre-emptive rights attach to the Trust Units.

SPECIAL VOTING UNIT

The Trust  Indenture  also  provides for the issuance of special  voting units
which are to be issued to a trustee  and which are  entitled to such number of
votes at meetings of  Unitholders  equal to the number of Trust Units reserved
for issuance that such special  voting units  represent,  such number of votes
and any other rights or  limitations  prescribed  by the Board of Directors of
ARC Resources when the Board authorizes issuing such special voting units.

A Special  Voting Unit has been  designated  by the Board of  Directors of ARC
Resources as the Special Voting Unit,  Exchangeable  Shares  ("Special  Voting
Unit").  The Special  Voting Unit possesses a number of votes for the election
of directors of ARC Resources and on all other matters  submitted to a vote of
Unitholders equal to the number of outstanding  Exchangeable  Shares from time
to time not owned by Trust or ARC Subco.  The  holders of Trust  Units and the
holder of the  Special  Voting  Unit vote  together  as a single  class on all
matters.

In the event of any  liquidation,  dissolution  or  winding-up  of Trust,  the
holder of the  Special  Voting Unit will not be entitled to receive any of our
assets  available for  distribution to Unitholders.  The holder of the Special
Voting Unit will not be entitled to receive dividends. The Special Voting Unit
has been issued to Computershare  Trust Company of Canada, as trustee. At such
time as the Special  Voting Unit has no votes attached to it because there are
no Exchangeable  Share  outstanding  that are not owned by Trust or ARC Subco,
the Special Voting Unit will be cancelled.

THE TRUST INDENTURE

The Trust Indenture,  among other things, provides for the calling of meetings
of  Unitholders,  the  conduct of business  thereof,  notice  provisions,  the
appointment   and   removal  of  the  Trustee  and  the  form  of  Trust  Unit
certificates.   The  Trust  Indenture  may  be  amended  from  time  to  time.
Substantive amendments to the Trust Indenture,  including early termination of
the Trust and the sale or transfer of the property of the Trust as an entirety
or substantially  as an entirety  requires  approval by Special  Resolution of
Unitholders.  Any approval or consent of Unitholders in relation to any matter
required  by any  regulatory  body will  require a majority  of, or such other
level of approval  of  Unitholders  as may be  stipulated  by such  regulatory
authority, including as to the exclusion of interested or other Unitholders in
the calculation of such level of approval. See "Meetings and Voting".

The following is a summary of certain provisions of the Trust Indenture. For a
complete description of such indenture,  reference should be made to the Trust
Indenture, a copy of which has been filed on SEDAR at www.sedar.com, or may be
obtained from the Trustee.

TRUSTEE

Computershare  Trust  Company  of Canada is the  trustee of the Trust and also
acts as the  transfer  agent for the Trust Units.  The Trustee is  responsible
for, among other things: (a) accepting subscriptions for Trust

<PAGE>
                                      34


Units and issuing Trust Units  pursuant  thereto;  (b)  maintaining  books and
records of the Trust and providing  timely  reports to holders of Trust Units;
and (c) paying cash distributions to Unitholders. The Trust Indenture provides
that the  Trustee  shall  exercise  its  powers  and carry  out its  functions
thereunder as Trustee honestly, in good faith and in the best interests of the
Trust and Unitholders and, in connection therewith, shall exercise that degree
of care,  diligence and skill that a reasonably prudent trustee would exercise
in comparable circumstances.

The term of the  Trustee's  appointment  is until the next  annual  meeting of
Unitholders.  At each annual meeting the Trustee may be reappointed or changed
as determined by a majority of the votes cast at such meeting of  Unitholders.
The Trustee may resign upon 60 days' notice to the Trust. The Trustee may also
be removed by Special  Resolution of Unitholders.  Such resignation or removal
becomes effective upon the acceptance or appointment of a successor trustee.

ARC Resources  presently  administers the Trust on behalf of the Trustee.  ARC
Resources,  on behalf of the  Trustee,  keeps  such  books and  records as are
necessary for the proper recording of the business transactions of the Trust.

The Trust Indenture  provides that the Trustee shall be under no liability for
any  action  or  failure  to act  unless  such  liabilities  arise  out of the
Trustee's gross negligence, wilful default or fraud. The Trustee, where it has
met its standard of care,  shall be indemnified out of the assets of the Trust
for any  taxes  or other  government  charges  imposed  upon  the  Trustee  in
consequence  of its  performance  of its duties  but shall have no  additional
recourse against Unitholders.  In addition, the Trust Indenture contains other
customary provisions limiting the liability of the Trustee.

FUTURE OFFERINGS

Under the Trust  Indenture,  the Trust  may offer  additional  Trust  Units or
rights to acquire  additional  Trust  Units at such times and on such terms as
the Board of Directors of ARC  Resources may  determine.  At the option of the
Trust,  the net  proceeds  from  any  offerings  may be used  to  finance  the
acquisition of additional properties,  make additional capital expenditures or
to repay indebtedness incurred in connection with such acquisitions.

MEETINGS AND VOTING

There  will be at least one  meeting of  Unitholders  held  annually.  Special
meetings of Unitholders  may be called at any time by the Trustee and shall be
called by the  Trustee  upon the  written  request of  Unitholders  holding in
aggregate not less than 20 percent of the Trust Units.  Notice of all meetings
of  Unitholders  shall be given to  Unitholders  at least 21 days prior to the
meeting.

Unitholders will be entitled at each annual meeting to appoint the Trustee, to
appoint the auditors of the Trust and to elect all the members of the Board of
Directors of ARC Resources.

OUR MANAGEMENT

The Trust Indenture provides for delegation to ARC Resources by the Trustee of
broad  discretion to administer  and manage our day to day  operations,  which
includes responsibility and authority to make executive decisions on behalf of
all of our direct or indirect  subsidiaries  and to exercise the powers of the
Trustee.   Without  limitation  of  the  foregoing,  ARC  Resources  has  been
specifically  delegated to provide certain administrative and support services
to us,  including those  necessary:  (i) to ensure  compliance with continuous
disclosure  obligations  under  applicable  securities  legislation;  (ii)  to
provide investor relations services;  (iii) to provide or cause to be provided
to Unitholders  all  information to which  Unitholders  are entitled under the
Trust Indenture; (iv) to call, hold and distribute materials including notices
of meetings

<PAGE>
                                      35


and information circulars in respect of all necessary meetings of Unitholders;
(v) to determine the amounts  payable from time to time to Unitholders  and to
arrange for distributions to Unitholders of distributable  income; and (vi) to
determine the timing and terms of future offerings of Trust Units, if any.

ARC Resources has accepted all such delegation and has agreed that, in respect
of such matters, it shall carry out its functions honestly,  in good faith and
in our best interests and the best interests of Unitholders and, in connection
therewith,  shall  exercise  that degree of care,  diligence  and skill that a
reasonably prudent person would exercise in comparable circumstances.

ARC FINANCIAL ADVISORY AGREEMENT

We  entered  an  agreement   dated  August  28,  2002  whereby  ARC  Financial
Corporation  agreed to provide us with certain ongoing  research and strategic
services  for a five year  period  without  further  cost.  This  ensures  the
continuing availability of research and strategic advice in the energy sector,
which has been  beneficial to us in the past.  ARC Financial  Corporation  has
also agreed not to, and will use reasonable  commercial  efforts, to cause any
of the ARC Financial group of companies,  not to act as manager or promoter of
another publicly listed energy related trust for a period of five years,  with
certain exceptions  relating to the ARC venture capital activities carried out
by any member of the ARC Financial group of companies.

LIMITATION ON NON-RESIDENT OWNERSHIP

In order that we maintain our status as a mutual fund trust under the Tax Act,
we  must  not be  established  or  maintained  primarily  for the  benefit  of
non-residents of Canada  ("non-residents")  within the meaning of the Tax Act.
Accordingly,  the Trust Indenture  provides that we shall, among other things,
take all necessary  steps to monitor the ownership of the Trust Units in order
that we  maintain  the status of a unit trust and a mutual  fund trust for the
purposes of the Tax Act. The Trust Indenture also provides that if at any time
we become aware that the beneficial  owners of 50 percent or more of the Trust
Units then outstanding are or may be non-residents or that such a situation is
imminent,  we shall  take  such  action as may be  necessary  to carry out the
foregoing intentions.

RIGHT OF REDEMPTION

Trust Units will be  redeemable  at any time on demand by the holders  thereof
upon delivery to us of the certificate or certificates representing such Trust
Units, accompanied by a duly completed and properly executed notice requesting
redemption.  Upon receipt of the redemption  request,  all rights to and under
the Trust Units  tendered for redemption  shall be surrendered  and the holder
thereof  shall be  entitled  to receive a price per Unit  ("Market  Redemption
Price") equal to the lesser of: (i) 90 percent of the market price,  being the
weighted  average trading price of the Trust Units on the principal  market on
which the Trust Units are quoted for trading  during the 10 trading day period
commencing immediately after the date on which the Trust Units are surrendered
for redemption;  and (ii) the closing market price on the principal  market on
which the Trust  Units are quoted for trading on the date that the Trust Units
are surrendered for redemption.

The  aggregate  cash Market  Redemption  Price payable by us in respect of any
Trust Units  surrendered  for  redemption  during any calendar  month shall be
satisfied  by way of a cash  payment on the last day of the  following  month;
provided  that  the  entitlement  of  Unitholders  to  receive  cash  upon the
redemption  of  their  Trust  Units is  subject  to a  number  of  conditions,
including the condition that the total amount payable by us in respect of such
Trust Units and all other  Trust Units  tendered  for  retraction  in the same
calendar  month  must not  exceed  $100,000  provided  that we may waive  such
condition in respect of any calendar month.

<PAGE>
                                      36


If a Unitholder  is not entitled to receive cash upon the  redemption of Trust
Units then we shall pay the Market  Redemption  Price for such Trust  Units on
the last day of the following month by distributing unsecured promissory notes
of ARC Resources ("ARC Resources Notes") having an aggregate  principal amount
equal to the aggregate Market Redemption Price of the Trust Units tendered for
redemption,  which notes will bear interest at the rate of 6 percent per annum
and will mature on the 15th anniversary of the date of issuance.

It is anticipated that the foregoing  retraction right will not be the primary
mechanism  for  holders of Trust Units to dispose of their  Trust  Units.  ARC
Resources  Notes  which  may  be  distributed  IN  SPECIE  to  Unitholders  in
connection  with a redemption  will not be listed on any stock exchange and no
market is expected to develop in the ARC Resources  Notes. ARC Resources Notes
may be subject to resale  restrictions  under applicable  securities laws. ARC
Resources  Notes  so  distributed  may be  qualified  investments  for  trusts
governed by registered retirement savings plans,  registered retirement income
trusts and deferred profit sharing plans.

TERMINATION OF THE TRUST

Unitholders  may vote to  terminate  the Trust at any meeting of  Unitholders,
subject to the following:  (a) a vote may only be held if requested in writing
by the holders of not less than 20 percent of the Trust Units; (b) a quorum of
50 percent of the issued and  outstanding  Trust Units is present in person or
by proxy;  and (c) the termination  must be approved by Special  Resolution of
Unitholders.

Unless the Trust is terminated or extended by vote of Unitholders earlier, the
Trustee  shall  commence to wind-up  the affairs of the Trust on December  31,
2095. In the event that the Trust is wound-up,  the Trustee will liquidate all
the assets of the Trust, pay, retire,  discharge or make provision for some or
all  obligations of the Trust and then  distribute  the remaining  proceeds of
sale to Unitholders.

REPORTING TO UNITHOLDERS

Our financial statements will be audited annually by an independent recognized
firm of chartered accountants. Our audited financial statements, together with
the report of such chartered  accountants,  will be mailed to Unitholders  and
the  unaudited  interim  financial  statements  of the Trust will be mailed to
Unitholders as prescribed by securities legislation.  Our year end is December
31.  We are  subject  to  the  continuous  disclosure  obligations  under  all
applicable securities legislation.

Unitholders  are entitled to inspect,  during normal  business  hours,  at the
offices of the Trustee, and, upon payment of reasonable reproduction costs, to
receive photocopies of certain material  contracts,  the Trust Indenture and a
listing of the registered holders of Trust Units.

DISTRIBUTION REINVESTMENT AND OPTIONAL TRUST UNIT PURCHASE PLAN

A plan has been established to provide Unitholders who are residents of Canada
(within  the  meaning  of  the  Tax  Act)  with  a  method  to  reinvest  cash
distributions by purchasing additional Trust Units.

                             CORPORATE GOVERNANCE

GENERAL

In  general,  ARC  Resources  has  been  delegated  substantially  all  of our
management  decisions.  Unitholders  are entitled to elect all of the Board of
Directors of ARC Resources  pursuant to the terms of the Trust Indenture.  The
Articles  of ARC  Resources  provides  that  the  Board  of  Directors  of ARC
Resources shall consist of a minimum of three and a maximum of nine directors.

<PAGE>
                                      37


TRUST INDENTURE

Pursuant to the Trust Indenture, Unitholders are entitled to direct the manner
in which we will vote our shares in ARC  Resources  at all meetings in respect
of  matters,  relating  to the  election of the  directors  of ARC  Resources,
approving its financial  statements and  appointing  auditors of ARC Resources
who shall be the same as our auditors.  Prior to exercising  our voting rights
in ARC Resources, each Unitholder is entitled to vote on the basis of one vote
per Trust Unit held,  and we are required to vote our shares in ARC  Resources
in accordance with the result of the vote of Unitholders.

DECISION MAKING

The Board of  Directors  of ARC  Resources  has a  mandate  to  supervise  the
management  of our  business  and  affairs  and to act with a view to our best
interests.  The Board of Directors of ARC Resources  supervises the management
of the  business  and  affairs of our  subsidiaries.  The Board of  Directors'
mandate  includes:  (a) the  responsibility  for  managing  our  affairs;  (b)
monitoring  our  management  and  our  activities;   (c)  reviewing  strategic
operating,  capital and  financial  plans;  and (d)  compliance  reporting and
corporate communications. In particular, significant operational decisions and
all decisions  relating to: (i) the  acquisition and disposition of properties
for a purchase price or proceeds in excess of an amount  prescribed  from time
to time by the Board of  Directors;  (ii) the approval of capital  expenditure
budgets; and (iii) establishment of credit facilities are made by the Board of
Directors of ARC  Resources.  In  addition,  the Trustee has  delegated  broad
discretion in relation to our day to day  operations to the Board of Directors
of ARC Resources  including all decisions relating to: (i) matters relating to
any offers for Trust Units;  (ii)  issuances of  additional  Trust Units;  and
(iii) the determination of the amount of distributable  income.  Any amendment
to the royalty  agreements  requires the approval of the Board of Directors of
ARC  Resources on our behalf.  The Board of Directors of ARC  Resources  holds
regularly  scheduled  meetings at least  quarterly  to review the business and
affairs of our subsidiaries and make any necessary decisions relating thereto.

The Trust  Indenture  gives to the Board of  Directors  of ARC  Resources  the
authority  to  exercise  the  rights,  powers and  privileges  for all matters
relating to the  maximization  of Unitholder  value in the context of an offer
including any Unitholder  rights  protection  plan, any defensive action to an
offer, any directors circular in response to an offer, any regulatory or court
proceeding relating to an offer and any related or ancillary matter.

BOARD OF DIRECTORS OF ARC RESOURCES

ARC Resources has a Board of Directors consisting of eight individuals, all of
whom have  been  elected  by  Unitholders,  including  by the  holders  of the
Exchangeable Shares through the Special Voting Unit.

The name, municipality of resident,  position held and principal occupation of
each director and officer of ARC Resources are set out below:

<TABLE>
<CAPTION>
           NAME AND                          OFFICES HELD
   MUNICIPALITY OF RESIDENCE             AND TIME AS DIRECTOR                      PRINCIPAL OCCUPATION
-----------------------------    ----------------------------------    ----------------------------------------
<S>                              <C>                                   <C>
Mac H. Van Wielingen(1)(3)(4)    Chairman of the Board and Director    Co-Chairman of ARC Financial Corporation
Calgary, Alberta, Canada         since May 3, 1996                     (an investment management company)
</TABLE>

<PAGE>
                                      38

<TABLE>
<CAPTION>
           NAME AND                          OFFICES HELD
   MUNICIPALITY OF RESIDENCE             AND TIME AS DIRECTOR                      PRINCIPAL OCCUPATION
-----------------------------    ----------------------------------    ----------------------------------------
<S>                              <C>                                   <C>
Walter DeBoni(1) (4) (5)         Vice Chairman and Director since      Independent Businessman
Calgary, Alberta, Canada         June 26, 1996

John P. Dielwart                 President, Chief Executive Officer    President and Chief Executive Officer of
Calgary, Alberta, Canada         and Director since May 3, 1996        ARC Resources

Frederic C. Coles(2)(3) (5)      Director since May 3, 1996            Independent Businessman
Calgary, Alberta, Canada

Fred J. Dyment(1)(2)             Director since April 17, 2003         Independent Businessman
Calgary, Alberta, Canada

Michael M. Kanovsky(1)(2)        Director since May 3, 1996            Independent Businessman
Victoria, B.C., Canada

Herbert C. Pinder, Jr.(6)        Director since January 1, 2006        Independent Businessman
Saskatoon, Saskatchewan, Canada

John M. Stewart(3)(4)(5)         Director since February 11, 1998      Vice Chairman of ARC Financial Corporation
Calgary, Alberta, Canada                                               (an investment management company)

Doug J. Bonner                   Senior Vice-President, Corporate      Senior Vice-President, Corporate
Calgary, Alberta, Canada         Development                           Development of ARC Resources

David P. Carey                   Senior Vice-President, Capital        Senior Vice-President, Capital Markets of
Calgary, Alberta, Canada         Markets                               ARC Resources

Susan D. Healy                   Senior Vice-President, Corporate      Senior Vice-President, Corporate Services
Calgary, Alberta,  Canada        Services                              of ARC Resources

Steven W. Sinclair               Senior Vice-President, Finance and    Senior Vice-President, Finance and Chief
Calgary, Alberta, Canada         Chief Financial Officer               Financial Officer of ARC Resources

Myron M. Stadnyk                 Senior Vice-President and Chief       Senior Vice-President and Chief Operating
Calgary, Alberta, Canada         Operating Officer                     Officer of ARC Resources

Terry M. Anderson                Vice-President, Operations            Vice-President, Operations of ARC Resources
Calgary, Alberta, Canada

Yvan Chretien                    Vice-President, Land                  Vice-President, Land of ARC Resources
Calgary, Alberta, Canada

P. Van R. Dafoe                  Treasurer                             Treasurer of ARC Resources
Calgary, Alberta, Canada

Allan R. Twa                     Secretary                             Partner, Burnet, Duckworth & Palmer LLP
Calgary, Alberta, Canada                                               (barristers and solicitors)
</TABLE>

Notes:
(1)  Member of Audit Committee.
(2)  Member of Reserves Committee.
(3)  Member of Human Resources and Compensation Committee.
(4)  Member of Policy and Board Governance Committee.
(5)  Member of Health, Safety and Environment Committee.
(6)  Herbert  Pinder  joined  the Board of  Directors  on  January 1, 2006 and
     subsequently  joined the Human Resources and  Compensation  Committee and
     the Policy and Board Governance Committee.

<PAGE>
                                      39


Each of the  directors and officers have held the position set forth as his or
her principal  occupation or the last five years except for Walter DeBoni who,
prior to February  2002,  was  President  and Chief  Executive  Officer of Bow
Valley  Energy Ltd. (an oil and gas  company)  and prior to November  2005 was
Vice- President, Canada Frontier & International Business of Husky Energy Inc.
(a  public  oil and gas  company);  Fred  Dyment  who  prior  to May  2001 was
President and Chief  Executive  Officer of Maxx Petroleum Ltd. (an oil and gas
company);  Steven W. Sinclair,  who prior to November 2005 was Vice-President,
Finance and Chief  Financial  officer;  David P. Carey who,  prior to November
2001, was Director of Investor Relations of Gulf Canada Resources and prior to
November 2005 was Vice-President, Business Development; Doug Bonner, who prior
to November 2005 was Vice-President,  Engineering; Myron J. Stadnyk, who prior
to September  2004, was Vice  President  Operations and prior to November 2005
was Vice-President, Operations and Land, of ARC Resources; and Susan D. Healy,
who prior to September  2004,  was  Vice-President  Land and prior to November
2005 was Vice-President, Corporate Services of ARC Resources; P. Van R, Dafoe,
who prior to March 2005, was  Controller of ARC Resources;  Terry M. Anderson,
who prior to November  2005, was Manager,  Field  Operations of ARC Resources;
and Yvan  Chretien,  who  prior to  November  2005,  was Land  Manager  of ARC
Resources.

The following  comprises a brief description of the background of the officers
of ARC Resources.

JOHN P. DIELWART, B.SC., P.ENG.

Mr. Dielwart is President and CEO of ARC Resources and has overall  management
responsibility  for the Trust.  Prior to joining ARC Financial  Corporation in
1994,  Mr.  Dielwart spent 12 years with a major Calgary based oil and natural
gas  engineering  consulting  firm, as senior  vice-president  and a director,
where  he  gained  extensive  technical  knowledge  of  oil  and  natural  gas
properties in western Canada.  He began his career working for five years with
a major oil and natural gas  company in Calgary.  Mr.  Dielwart is a member of
the Associate of  Professional  Engineers,  Geologists  and  Geophysicists  of
Alberta  (APEGGA).  Mr.  Dielwart  is a recent  past  Chairman of the board of
governors for the Canadian Association of Petroleum Producers (CAPP). He holds
a Bachelor of Science with Distinction (Civil Engineering) degree,  University
of Calgary. He has been a director of ARC Resources since 1996.

STEVEN W. SINCLAIR, B. COMM., CA

Mr. Sinclair is Senior  Vice-President  Finance and Chief Financial Officer of
ARC  Resources  and oversees all of the  financial  affairs of the Trust.  Mr.
Sinclair has a Bachelor of Commerce from the  University of Calgary,  obtained
his  Chartered  Accountant's  designation  in  1981  and  has  over  20  years
experience  within the finance,  accounting  and taxation areas of the oil and
gas industry. Mr. Sinclair has been with the Trust since 1996. Mr. Sinclair is
a member of both the Alberta and Canadian Institute of Chartered Accountants

DOUGLAS J. BONNER, B.SC., P.ENG.

Mr. Bonner is Senior  Vice-President,  Corporate  Development of ARC Resources
and is responsible for all exploitation and development activities. He holds a
B.Sc. in Geological  Engineering from the University of Manitoba. Mr. Bonner's
major  area  of  expertise  is  reservoir  engineering  and he  has  extensive
technical  knowledge of oil and natural gas fields throughout  western Canada,
the east coast and northern Canada.  Mr. Bonner is a member of the Association
of Professional  Engineers,  Geologists and Geophysicists of Alberta. Prior to
joining ARC  Resources in 1996,  Mr.  Bonner spent 18 years with various major
oil and natural gas companies in positions of increasing responsibility.

<PAGE>
                                      40


DAVID P. CAREY, B.SC., P.ENG., MBA

Mr. Carey is Senior  Vice-President,  Capital  Markets of ARC Resources and is
responsible for all facets of business development and investor relations.  He
holds  both  a  B.Sc.  in  Geological  Engineering  and  a  MBA  from  Queen's
University.  Mr. Carey has over 20 years of diverse experience in the Canadian
and  international  energy  industries  covering  exploration,  production and
project  evaluations in western Canada,  oilsands,  the Canadian frontiers and
internationally.  Mr.  Carey is a member of the  Association  of  Professional
Engineers,  Geologists  and  Geophysicists  of  Alberta.  Prior to joining ARC
Resources in 2001,  Mr. Carey held senior  positions  with Athabasca Oil Sands
Investments Inc. and a major Canadian oil and gas company.

SUSAN D. HEALY, P. LAND

Ms. Healy is Senior Vice-President,  Corporate Services and is responsible for
all office services and human resources related  activities.  Ms. Healy joined
the  Trust  at  inception  in July  1996,  bringing  with her over 17 years of
diverse  experience  gained  from  working  with junior and senior oil and gas
companies.  Ms.  Healy has a  Professional  Land  designation  granted  by the
Canadian Association of Petroleum Landmen.

MYRON M. STADNYK, B.SC., P.ENG.

Mr.  Stadnyk  is Senior  Vice-President  and Chief  Operating  Officer  of ARC
Resources and is responsible for all of ARC Resources' operational activities.
He has  18  years  experience  in  all  aspects  of  oil  and  gas  production
operations.  Prior to joining ARC Resources in 1997, Mr. Stadnyk worked with a
major oil and gas company in both domestic and  international  operations  and
oil and gas facility  design and  construction.  He has a B.Sc.  in Mechanical
Engineering  and is a member of the  Association  of  Professional  Engineers,
Geologists and Geophysicists in Alberta and Saskatchewan.

TERRY M. ANDERSON

Mr. Anderson is Vice-President, Operations of ARC Resources and is responsible
for all of ARC Resources' operational activities.  He has a B.Sc. in Petroleum
Engineering and is a member of the  Association of  Professional  Engineers in
Alberta,  Saskatchewan  and British  Columbia.  Mr.  Anderson  has 12 years of
experience  in  drilling,   completion,   pipeline,  facility  and  production
operations.  Prior to joining ARC  Resources in 2000, he worked at a major oil
and gas company.

YVAN CHRETIEN

Mr. Chretien is  Vice-President,  Land of ARC Resources and is responsible for
all of ARC Resources' land related activities. He has 15 years of land related
experience.  Prior to joining ARC  Resources in 2001,  Mr Chretien  worked for
both senior and intermediate oil and gas companies.

P. VAN R. DAFOE

Mr. Dafoe is  Treasurer of ARC  Resources  and is  responsible  for all of ARC
Resources'  treasury  related  activities.  He has a  Bachelor  of  Commerce -
Honours from the University of Manitoba and obtained his Certified  Management
Accountant's designation in 1995. Mr. Dafoe joined ARC Resources in 1999 after
13 years with various  companies in the finance and accounting area of the oil
and gas industry.

<PAGE>
                                      41


ALLAN R. TWA, Q.C.

Mr. Twa is the Corporate  Secretary of ARC Resources.  A member of the Alberta
Bar since  1971,  Mr. Twa is a partner  in the law firm  Burnet,  Duckworth  &
Palmer LLP. Mr. Twa holds a B.A.  (Political  Science) from the  University of
Calgary,  a  LL.B.  from  the  University  of  Alberta  and a LL.M.  from  the
University  of  London,  England.  Over the last 30  years,  Mr.  Twa has been
engaged in a legal practice involving legal administration of public companies
and trusts, corporate finance, and mergers and acquisitions.

Mac Van  Wielingen is the Chairman and a Director of ARC  Resources  and was a
director of Gauntlet  Energy  Corporation  which secured  creditor  protection
pursuant to the COMPANIES' CREDITORS  ARRANGEMENT ACT on June 17, 2003 and was
subsequently acquired by Ketch Resources Ltd. in December, 2003.

All of the  directors  of ARC  Resources  were elected on May 12, 2005 to hold
office  until the next  annual  general  meeting  of ARC  Resources,  which is
scheduled for May 15, 2006.  As at March 22, 2006,  the directors and officers
of ARC Resources, as a group,  beneficially owned, directly or indirectly,  or
exercised control or direction over,  942,087 Trust Units or approximately 0.5
percent of the outstanding  Trust Units,  and 989,728  Exchangeable  Shares or
approximately 63.1 percent of the outstanding  Exchangeable  Shares. If all of
the  Exchangeable  Shares had been  exchanged  for Trust Units at the Exchange
Ratio in effect on March 22, 2006, the directors and officers of ARC Resources
as a group would hold 2,804,617  Trust Units or  approximately  1.4 percent of
the outstanding Trust Units as at March 22, 2006.

                          AUDIT COMMITTEE DISCLOSURES

Multilateral  Instrument 52-110 ("MI 52-110") relating to audit committees has
mandated certain  disclosures for inclusion in this Annual  Information  Form.
The text of the Audit  Committee's  mandate is  attached as Appendix C to this
Annual Information Form.

The members of the Audit  Committee  are Fred J.  Dyment,  chairman,  and Walt
DeBoni,  Michael  Kanovsky and Mac Van Wielingen,  each of whom is independent
and  financially  literate  within the  meaning of MI  52-110.  The  following
comprises a brief summary of each member's education and experience:

FRED J. DYMENT

Mr.  Dyment  has 29  years  experience  in the  oil and  gas  business  and is
currently  an  independent  businessman.  His past  business  career  included
positions as President  and CEO for Maxx  Petroleum  and  President and CEO of
Ranger Oil Limited.  Mr. Dyment  received a Chartered  Accountant  designation
from the province of Ontario in 1972 and is a member of the Alberta  Institute
of  Chartered  Accountants.  Mr.  Dyment is a Director  of Tesco  Corporation,
Transglobe  Energy  Corporation and ZCL Composites Inc. He has been a Director
of ARC Resources since 2003.

WALT DEBONI, P.ENG., MBA

Mr. DeBoni has held numerous top executive  posts in the oil and gas industry,
including V.P. Canada Frontier & International Business, for Husky Energy Inc.
until  November  2005 and is an  independent  businessman.  Mr. DeBoni holds a
B.A.Sc. Chem. Eng. From the University of British Columbia, an MBA degree with
a major in  Finance  from the  University  of  Calgary  and is a member of the
Association of Professional Engineers, Geologists and Geophysicists of Alberta
and the  Society of  Petroleum  Engineers.  Mr.  DeBoni is a Director  of Niko
Resources  Ltd. He is a past Chairman of the Petroleum

<PAGE>
                                      42


Society of CIM, a past Director of the Society of Petroleum  Engineers and has
been a Director of ARC Resources since 1996.

MICHAEL KANOVSKY, B.SC., P.ENG., MBA

Mr.  Kanovsky  graduated  from  Queen's  University  and the  Ivey  School  of
Business.  Mr.  Kanovsky's  business  career  included  the  position of VP of
Corporate  Finance  with a major  Canadian  investment  dealer,  director  and
officer of  Northstar  Energy  Corporation,  and a director  and  Chairman  of
PowerLink Corporation (electrical cogeneration). Mr. Kanovsky is a Director of
Accrete Energy Inc.,  Bonavista Energy Trust, Devon Energy  Corporation,  Pure
Technologies  Inc. and  TransAlta  Corporation.  He has been a Director of ARC
Resources since 1996.

MAC VAN WIELINGEN

Mr. Van Wielingen  became chairman of ARC in 2003, prior to which he served as
Vice-Chairman  and Director of ARC Resources Ltd. since its formation in 1996.
He is  Co-Chairman  and was a founder of ARC  Financial  Corporation  in 1989.
Previously  Mr. Van  Wielingen was a Senior  Vice-President  and Director of a
major  national  investment  dealer  responsible  for  all  corporate  finance
activities in Alberta.  He has managed numerous  significant  corporate merger
and acquisition transactions,  capital raising projects and equity investments
relating to the energy sector.  Mr. Van Wielingen is a director of Western Oil
Sands  Inc.  Mr.  Van  Wielingen  holds an Honours  Business  Degree  from the
University of Western Ontario  Business  School and has studied  post-graduate
Economics at Harvard University.  Mr. Van Wielingen has been a Director of ARC
Resources since 1996.

The Audit Committee has not adopted  specific  policies and procedures for the
engagement of non-audit services and pre-approves each such engagement or type
of engagement for every fiscal year.

Our external  auditor is Deloitte & Touche LLP. The  following is a summary of
the external audit services fees by category.

AUDIT FEES

The aggregate fees billed by our external auditor for audit services are:

         2005     -     $280,750

         2004     -     $235,000

AUDIT RELATED FEES

The  aggregate  fees billed by our external  auditor for assurance and related
services that are reasonably related to the performance of the audit or review
of the financial statements (not included in audit services fees) are:

         2005     -     $110,900

         2004     -      $46,165

<PAGE>
                                      43


TAX FEES

The aggregate fees billed by our external  auditor for  professional  services
for municipal property tax compliance, tax advice and tax planning are:

         2005     -     $110,532
         2004     -      $72,503

ALL OTHER FEES

The aggregate fees billed by our external auditor for products and services
not included under the headings: Audit Fees, Audit Related Fees, Tax Fees and
All Other Fees.

         2005     -     $0

         2004     -     $0


                             CONFLICTS OF INTEREST

Circumstances  may  arise  where  members  of the  Board of  Directors  of ARC
Resources  serve  as  directors  or  officers  of  corporations  which  are in
competition  to our interests.  No assurances can be given that  opportunities
identified by such board members will be provided to us.

The BUSINESS  CORPORATIONS  ACT  (Alberta)  provides  that in the event that a
director has an interest in a contract or proposed contract or agreement,  the
director  shall  disclose his interest in such contract or agreement and shall
refrain  from voting on any matter in respect of such  contract  or  agreement
unless  otherwise  provided  under such Act. To the extent that  conflicts  of
interest  arise,  such  conflicts  will be  resolved  in  accordance  with the
provisions of such Act.

          INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS

There is no material interest,  direct or indirect,  of any director or senior
officer,  or to our  knowledge  any  person or  company  that is the direct or
beneficial  owner,  or who  exercises  control or direction  over more than 10
percent of  outstanding  Trust Units,  or any associate or affiliate of any of
the foregoing,  in any  transaction  within the three most recently  completed
financial years.

                         DISTRIBUTIONS TO UNITHOLDERS

The  following per Trust Unit  distributions  have been made in the last three
completed financial years:

               2003           DISTRIBUTION PER TRUST UNIT
          ---------------     ---------------------------
          First Quarter                  $0.45
          Second Quarter                 $0.45
          Third Quarter                  $0.45
          Fourth Quarter                 $0.45

               2004
          ---------------
          First Quarter                  $0.45
          Second Quarter                 $0.45
          Third Quarter                  $0.45
          Fourth Quarter                 $0.45

<PAGE>
                                      44


               2005
          ---------------
          First Quarter                  $0.45
          Second Quarter                 $0.45
          Third Quarter                  $0.49
          Fourth Quarter                 $0.60


In certain  circumstances,  distributions  may be  restricted by our borrowing
agreements.  For more  information  see  "Other  Information  Relating  to Our
Business - Borrowing".  Cash distributions paid to Unitholders in 2003 were 15
percent tax deferred,  2004 cash distributions were 6 percent tax deferred and
2005 cash distributions were 2 percent tax deferred. For more information, see
"Our Business - Cash Distributions and Distribution Policy".


                 PRICE RANGE AND TRADING VOLUME OF TRUST UNITS
                            AND EXCHANGEABLE SHARES

The Trust  Units are  listed  and posted  for  trading  on the  Toronto  Stock
Exchange  ("TSX").  The  trading  symbol for the Trust  Units is  AET.UN.  The
following  table sets forth the high and low closing  prices and the aggregate
volume of trading of the Trust Units on the TSX for the periods  indicated (as
quoted by the TSX):

                                                   TORONTO STOCK EXCHANGE
                                                   ----------------------
    2005 PERIOD                                HIGH         LOW          VOLUME
    -----------                                ----         ---          ------
                                              $           $
    January                                   19.58       17.40      10,344,373
    February                                  20.21       18.80      21,054,229
    March                                     19.20       17.15      16,314,032
    April                                     18.50       17.09      13,437,069
    May                                       18.99       17.19      12,562,645
    June                                      20.19       18.70      12,719,069
    July                                      22.35       19.95       9,672,059
    August                                    23.25       21.05      12,566,204
    September                                 24.10       21.80      15,391,729
    October                                   24.20       20.71      16,006,795
    November                                  25.78       21.75      12,437,591
    December                                  27.20       26.30      12,041,307


The  Exchangeable  Shares are listed  and posted for  trading on the TSX.  The
trading symbol for the  Exchangeable  Shares is ARX. The following  table sets
forth the high and low closing  prices and the aggregate  volume of trading of
the Exchangeable Shares on the TSX for the periods indicated (as quoted by the
TSX):

                                                   TORONTO STOCK EXCHANGE
                                                   ----------------------
    2005 PERIOD                                HIGH         LOW          VOLUME
    -----------                                ----         ---          ------
                                               $             $
    January                                    33.46        29.61         3,070
    February                                   33.50        32.04        11,154
    March                                      33.20        30.15         8,338
    April                                      30.85        29.29           875
    May                                        33.00        31.23         5,765

<PAGE>
                                      45


                                                   TORONTO STOCK EXCHANGE
                                                   ----------------------
    2005 PERIOD                                HIGH         LOW          VOLUME
    -----------                                ----         ---          ------
                                               $             $
    June                                       36.24        33.10         1,545
    July                                       39.09        36.50         8,481
    August                                     47.00        37.00        18,135
    September                                  43.00        39.38        11,983
    October                                    41.30        38.00        12,354
    November                                   47.00        40.38         5,634
    December                                   50.51        47.00         1,280


                               STABILITY RATING

Dominion Bond Rating Service Limited  ("DBRS") has assigned a stability rating
of STA-5 (high) to the Trust Units.  The stability rating is based on a rating
scale  developed by DBRS that  provides an indicator of both the stability and
sustainability of an income fund's  distributions per unit. Ratings categories
range from STA-1 to STA-7,  with STA-1 being the highest.  In  addition,  DBRS
further separates the ratings into "high", "middle" and "low" subcategories to
indicate  where  they fall  within  the  rating  category.  Ratings  take into
consideration   the  seven  main  factors  of:  (1)   operating  and  industry
characteristics;   (2)  asset   quality;   (3)  financial   flexibility;   (4)
diversification; (5) size and market position; (6) sponsorship/governance; and
(7) growth.  In addition,  consideration  is given to specific  structural  or
contractual elements that may eliminate or mitigate risks or other potentially
negative factors.

Specifically,  income funds rated as STA-5 are considered by DBRS to have weak
distribution  per unit stability and  sustainability.  An income fund rated as
STA-5 is subject to many of the same cyclical,  seasonal and economic  factors
as the  higher  STA-4  rating  category,  but the lack of  diversification  is
generally more  pronounced and such income funds will tend to be below average
in several areas.

A rating is not a recommendation  to buy, sell or hold any security and may be
subject to revision or withdrawal at any time by DBRS.

                             INDUSTRY REGULATIONS

The oil and  natural  gas  industry  is  subject  to  extensive  controls  and
regulations  governing its  operations  (including  land tenure,  exploration,
development,  production,  refining,  transportation and marketing) imposed by
legislation  enacted  by  various  levels of  government  and with  respect to
pricing  and  taxation  of  oil  and  natural  gas  by  agreements  among  the
governments of Canada,  Alberta,  British  Columbia and  Saskatchewan,  all of
which should be carefully considered by investors in the oil and gas industry.
It is not expected that any of these controls or  regulations  will affect our
operations in a manner  materially  different than they would affect other oil
and gas  companies of similar  size.  All current  legislation  is a matter of
public  record and we are unable to predict  what  additional  legislation  or
amendments may be enacted. Outlined below are some of the principal aspects of
legislation, regulations and agreements governing the oil and gas industry.

PRICING AND MARKETING OF OIL AND NATURAL GAS

The producers of oil are entitled to negotiate sales  contracts  directly with
oil purchasers,  with the result that the market  determines the price of oil.
Such price depends in part on oil quality,  prices of competing oils, distance
to market,  the value of refined products and the supply/demand  balance.  Oil
exporters  are

<PAGE>
                                      46


also entitled to enter into export contracts with terms not exceeding one year
in the case of light  crude oil and two years in the case of heavy  crude oil,
provided  that an order  approving  such  export  has been  obtained  from the
National  Energy  Board of  Canada  (the  "NEB").  Any oil  export  to be made
pursuant to a contract of longer  duration (to a maximum of 25 years) requires
an exporter to obtain an export  licence from the NEB and the issuance of such
licence requires the approval of the Governor in Council.

The  price of  natural  gas is  determined  by  negotiation  among  producers,
marketers  and  purchasers.  Natural  gas  exported  from Canada is subject to
regulation  by the NEB and the  Government  of Canada.  Exporters  are free to
negotiate  prices with  purchasers,  provided that the export  contracts  must
continue  to  meet  certain  other  criteria  prescribed  by the  NEB  and the
Government  of Canada.  Natural gas exports for a term of less than 2 years or
for a term of 2 to 20 years (in  quantities  of not more than 30,000  m3/day),
must be made  pursuant  to an NEB  order.  Any  natural  gas export to be made
pursuant  to a  contract  of longer  duration  (to a maximum of 25 years) or a
larger quantity  requires an exporter to obtain an export licence from the NEB
and the  issuance of such  licence  requires  the  approval of the Governor in
Council.

PIPELINE CAPACITY

Although pipeline  expansions are ongoing,  the lack of firm pipeline capacity
continues  to affect the oil and natural gas industry and limit the ability to
produce and to market  natural gas  production.  The  governments  of Alberta,
British  Columbia  and  Saskatchewan  also  regulate the volume of natural gas
which may be removed from those provinces for  consumption  elsewhere based on
such  factors  as  reserve  ability,  transportation  arrangements  and market
considerations.  The prorationing of capacity on the inter-provincial pipeline
systems also continues to affect the ability to export oil and natural gas.

THE NORTH AMERICAN FREE TRADE AGREEMENT

The North American Free Trade  Agreement  ("NAFTA")  among the  governments of
Canada,  United  States of America and Mexico  became  effective on January 1,
1994.  NAFTA  carries  forward  most of the  material  energy  terms  that are
contained in the Canada United States Free Trade  Agreement.  Canada continues
to remain free to determine  whether exports of energy resources to the United
States or Mexico will be allowed,  provided  that any export  restrictions  do
not:  (i) reduce the  proportion  of energy  resources  exported  relative  to
domestic use (based upon the proportion prevailing in the most recent 36 month
period);  (ii) impose an export price higher than the domestic price; or (iii)
disrupt normal  channels of supply.  All three  countries are prohibited  from
imposing minimum export or import price requirements.

NAFTA contemplates the reduction of Mexican restrictive trade practices in the
energy  sector and prohibits  discriminatory  border  restrictions  and export
taxes. The agreement also  contemplates  clearer  disciplines on regulators to
ensure  fair   implementation  of  any  regulatory  changes  and  to  minimize
disruption  of  contractual  arrangements,  which is  important  for  Canadian
natural gas exports.

PROVINCIAL ROYALTIES AND INCENTIVES

In  addition  to  federal  regulation,   each  province  has  legislation  and
regulations   which  govern  land   tenure,   royalties,   production   rates,
environmental   protection  and  other  matters.   The  royalty  regime  is  a
significant  factor in the  profitability  of crude oil,  natural gas liquids,
sulphur and natural gas production. Royalties payable on production from lands
other than Crown  lands are  determined  by  negotiations  between the mineral
owner and the  lessee,  although  production  from such  lands is  subject  to
certain  provincial  taxes and  royalties.  Crown  royalties are determined by
governmental  regulation  and are generally  calculated as a percentage of the
value of the gross production. The rate of royalties payable generally depends
in  part on  prescribed  reference  prices,  well  productivity,  geographical
location,  field  discovery  date and the  type or  quality  of the  petroleum
product produced.

<PAGE>
                                      47


From time to time the  governments of the western  Canadian  provinces  create
incentive  programs for  exploration  and  development.  Such  programs  often
provide for royalty rate reductions, royalty holidays and tax credits, and are
generally  introduced when commodity prices are low. The programs are designed
to encourage  exploration and development  activity by improving  earnings and
cash flow within the industry.  Royalty  holidays and reductions  would reduce
the amount of Crown  royalties paid by oil and gas producers to the provincial
governments  and would  increase the net income and funds from  operations  of
such  producers.  However,  the trend in recent years has been for  provincial
governments to allow such incentive  programs to expire without  renewal,  and
consequently few such incentive programs are currently operative.

In the Province of Alberta,  a producer of oil or natural gas is entitled to a
credit  against  the  royalties  payable to the Crown by virtue of the Alberta
royalty  tax  credit  ("ARTC")  program.  The  ARTC  rate is  based on a price
sensitive formula and the ARTC rate varies between 75 percent at prices at and
below $100 per m(3) and 25  percent at prices at and above $210 per m(3).  The
ARTC rate is applied to a maximum of  $2,000,000  of Alberta  Crown  royalties
payable for each producer or associated group of producers. Crown royalties on
production  from  producing  properties  acquired from a corporation  claiming
maximum  entitlement to ARTC will generally not be eligible for ARTC. The rate
will be established quarterly based on the average par price, as determined by
the Alberta Department of Energy for the previous quarterly period.

Crude oil and natural  gas royalty  programs  for  specific  wells and royalty
reductions  reduce  the  amount of Crown  royalties  we pay to the  provincial
governments.  In general,  the ARTC program provides a rebate on Alberta Crown
royalties paid in respect of eligible producing properties.

LAND TENURE

Crude  oil  and  natural  gas  located  in  the  western  provinces  is  owned
predominantly by the respective provincial governments. Provincial governments
grant  rights to explore  for and  produce  oil and  natural  gas  pursuant to
leases,  licences and permits for varying terms from 2 years and on conditions
set forth in provincial legislation including requirements to perform specific
work or make payments.  Oil and natural gas located in such provinces can also
be privately  owned and rights to explore for and produce such oil and natural
gas are granted by lease on such terms and conditions as may be negotiated.

ENVIRONMENTAL REGULATION

The oil and  natural  gas  industry  is  currently  subject  to  environmental
regulations pursuant to a variety of provincial and federal legislation.  Such
legislation  provides  for  restrictions  and  prohibitions  on the release or
emission of various  substances  produced in association  with certain oil and
gas industry operations.  In addition, such legislation requires that well and
facility  sites be abandoned and reclaimed to the  satisfaction  of provincial
authorities.   Compliance  with  such  legislation  can  require   significant
expenditures  and a breach of such  requirements  may result in  suspension or
revocation  of necessary  licenses and  authorizations,  civil  liability  for
pollution damage and the imposition of material fines and penalties.

Environmental   legislation  in  Alberta  has  been   consolidated   into  the
ENVIRONMENTAL  PROTECTION AND ENHANCEMENT  ACT (Alberta) (the "AEPEA"),  which
came into  force on  September  1, 1993 and the OIL AND GAS  CONSERVATION  ACT
(Alberta)  (the  "OGCA").  The AEPEA and OGCA  impose  stricter  environmental
standards,  require  more  stringent  compliance,   reporting  and  monitoring
obligations and significantly increase penalties.  We are committed to meeting
our  responsibilities  to protect  the  environment  wherever  we operate  and
anticipate  making  increased  expenditures  of both a capital  and an expense
nature  as a  result  of  the  increasingly  stringent  laws  relating  to the
protection of the environment and will be taking

<PAGE>
                                      48


such  steps as  required  to ensure  compliance  with the  AEPEA  and  similar
legislation in other jurisdictions in which we operate. We believe that we are
in material compliance with applicable environmental laws and regulations.  We
also  believe that it is  reasonably  likely that the trend  towards  stricter
standards in environmental legislation and regulation will continue.

British  Columbia's  ENVIRONMENTAL  ASSESSMENT  ACT became  effective June 30,
1995. This  legislation  rolls the previous  processes for the review of major
energy  projects into a single  environmental  assessment  process with public
participation in the environmental review process.

In  Saskatchewan,  environmental  compliance is governed by the  ENVIRONMENTAL
MANAGEMENT AND PROTECTION ACT  (Saskatchewan) and the OIL AND GAS CONSERVATION
ACT (Saskatchewan).

In December 2002 the  Government of Canada  ratified the Kyoto Protocol and it
became legally binding on February 16, 2005. This protocol calls for Canada to
reduce its  greenhouse gas emissions to 6 percent below 1990 levels during the
period between 2008 and 2012. See also "Risk Factors - Environmental Concerns"
and Risk Factors - Kyoto Protocol".

                                 RISK FACTORS

The following is a summary of certain risk factors relating to the business of
the  Trust  which  prospective  investors  should  carefully  consider  before
deciding whether to purchase Trust Units or Exchangeable Shares.

VOLATILITY OF OIL AND NATURAL GAS PRICES

Our operational results and financial condition,  and therefore the amounts we
pay to  Unitholders,  will be  dependent  on the prices  received  for oil and
natural gas  production.  Oil and natural  gas prices have  fluctuated  widely
during  recent  years and are  determined  by economic  and in the case of oil
prices,  political factors.  Supply and demand factors,  including weather and
general economic conditions as well as conditions in other oil and natural gas
regions impact  prices.  Any movement in oil and natural gas prices could have
an effect on our financial condition and therefore on the distributable income
to be distributed to holders of Trust Units. We may manage the risk associated
with  changes in  commodity  prices by entering  into oil or natural gas price
hedges. If we hedge our commodity price exposure,  we will forego the benefits
we would  otherwise  experience  if  commodity  prices  were to  increase.  In
addition,  commodity  hedging  activities  could  expose us to losses.  To the
extent  that we engage in risk  management  activities  related  to  commodity
prices, we will be subject to credit risks associated with counterparties with
which we contract.

RESERVES ESTIMATES

The reserves and recovery  information  contained in the GLJ Report is only an
estimate and the actual  production and ultimate  reserves from the properties
may be greater or less than the estimates  prepared by GLJ. The GLJ Report has
been prepared using certain commodity price assumptions which are described in
the notes to the reserves  tables.  If we realize  lower prices for crude oil,
natural gas liquids  and  natural gas and they are  substituted  for the price
assumptions utilized in those reserves reports, the present value of estimated
future net cash flows for our  reserves  would be  reduced  and the  reduction
could  be  significant,   particularly   based  on  the  constant  price  case
assumptions.

<PAGE>
                                      49


VARIATIONS IN INTEREST RATES AND FOREIGN EXCHANGE RATES

An increase in interest  rates could result in a  significant  increase in the
amount we pay to service  debt,  resulting in a decrease in  distributions  to
Unitholders, as well as impact the market price of the Trust Units on the TSX.

World oil prices are quoted in Unites States dollars and the price received by
Canadian producers is therefore affected by the Canadian/U.S.  dollar exchange
rate that may  fluctuate  over time.  A material  increase in the value of the
Canadian dollar may negatively impact our net production revenue.

In addition,  the exchange rate for the Canadian dollar versus the U.S. dollar
has increased significantly over the last 12 months,  resulting in our receipt
of  fewer  Canadian  dollars  for  our  production  which  may  affect  future
distributions.  We have initiated  certain hedges to attempt to mitigate these
risks. To the extent that we engage in risk management  activities  related to
foreign  exchange  rates,  it will be subject to credit risk  associated  with
counterparties  with which we contract.  The increase in the exchange rate for
the Canadian  dollar and future  Canadian/United  States  exchange  rates will
impact future distributions and the future value of our reserves as determined
by independent evaluators.

PURCHASE OF PROPERTIES

The price we paid for the purchase of the  properties is based on  engineering
and economic estimates of the reserves made by independent  engineers modified
to reflect our  technical  and economic  views.  These  assessments  include a
number of material  assumptions  regarding such factors as recoverability  and
marketability  of oil,  natural gas,  natural gas liquids and sulphur,  future
prices of oil,  natural  gas,  natural gas  liquids and sulphur and  operating
costs,  future capital  expenditures and royalties and other government levies
which will be imposed over the producing  life of the reserves.  Many of these
factors  are  subject to change and are beyond our  control and the control of
the operators of the properties.  In particular,  changes in the prices of and
markets for petroleum, natural gas, natural gas liquids and sulphur from those
anticipated at the time of making such  assessments  will affect the amount of
future  distributions  and as such the value of the Trust Units.  In addition,
all such estimates involve a measure of geological and engineering uncertainty
which could result in lower  production  and reserves  than  attributed to the
properties.  Actual  reserves  could vary  materially  from  these  estimates.
Consequently,  the reserves  acquired may be less than  expected,  which could
adversely impact cash flows and distributions to Unitholders.  See "ARC Energy
Trust - General Development of the Business".

ENHANCED OIL RECOVERY

We announced the Acquisition in December, 2005 which was comprised of a 45.57%
working  interest  in the North  Pembina  Cardium  Unit #1 in Alberta  and the
vendors'  working  interests  in  the  Redwater  area  of  Alberta.  For  more
information,  see "ARC Energy Trust - General Development of the Business". We
believe  the  Acquisition  strategically  positions  us for  participation  in
properties with large reserves of unrecovered  original oil in place which may
be amenable to secondary  recovery  techniques  such as carbon dioxide ("CO2")
miscible flooding.  The implementation of secondary oil recovery techniques on
properties  like  Redwater or the Pembina  Cardium Unit #1 would  require long
term supply agreements for CO2 and large scale infrastructure  investments. We
have just begun to devote resources to the study of such matters.  There is no
assurance  as to  when  or if  such  secondary  recovery  techniques  will  be
implemented, or if implemented,  when or if such secondary recovery techniques
would be successful.

CHANGES IN LEGISLATION

Income tax laws, or other laws or government  incentive  programs  relating to
the oil and gas  industry,  such as the  treatment  of mutual  fund trusts and
resource  taxation,  may in the future be changed or

<PAGE>
                                      50


interpreted in a manner that  adversely  affects us and our  Unitholders.  Tax
authorities  having  jurisdiction over us or Unitholders may disagree with how
we  calculate  our  income for tax  purposes  or could  change  administrative
practises to our detriment or the detriment of Unitholders.

We intend to continue  to qualify as a mutual  fund trust for  purposes of the
Tax  Act.  We  may  not,  however,  always  be  able  to  satisfy  any  future
requirements  for the  maintenance  of mutual  fund trust  status.  Should our
status as a mutual fund trust be lost or successfully challenged by a relevant
tax authority,  certain adverse consequences may arise for us and Unitholders.
Some of the significant consequences of losing mutual fund trust status are as
follows:

     o    We would  be  taxed  on  certain  types  of  income  distributed  to
          Unitholders, including income generated by the Royalties held by us.
          Payment  of  this  tax  may  have  adverse   consequences  for  some
          Unitholders,  particularly  Unitholders  that are not  residents  of
          Canada  and  residents  of Canada  that are  otherwise  exempt  from
          Canadian income tax.

     o    We would cease to be eligible for the capital gains refund mechanism
          available  under  Canadian tax laws if it ceased to be a mutual fund
          trust.

     o    Trust Units held by  Unitholders  that are not  residents  of Canada
          would become taxable Canadian property.  These non-resident  holders
          would be subject to Canadian  income tax on any gains  realized on a
          disposition of Trust Units held by them.

     o    Trust  Units  would  not  constitute   qualified   investments   for
          registered retirement savings plans ("RRSPs"), registered retirement
          income funds ("RRIFs"), registered education savings plans ("RESTs")
          or deferred  profit sharing plans  ("DPSPs").  If, at the end of any
          month,  one of these  exempt  plans  holds  Trust Units that are not
          qualified investments, the plan must pay a tax equal to 1 percent of
          the fair market value of the Trust Units at the time the Trust Units
          were   acquired  by  the  exempt  plan.  An  RRSP  or  RRIF  holding
          non-qualified  Trust  Units  would be subject to  taxation on income
          attributable  to the Trust  Units.  If an RESP  holds  non-qualified
          Trust  Units,  it may have its  registration  revoked  by the Canada
          Revenue Agency.

In  addition,  we may take  certain  measures  in the  future to the extent we
believe  necessary  to ensure  that we  maintain  the status as a mutual  fund
trust.  These  measures  could be adverse to certain  holders of Trust  Units,
particularly  non-residents  of Canada as  defined  in the Tax Act.  See "Risk
Factors - Non-resident Ownership of Trust Units".

MAINTENANCE OF DISTRIBUTIONS

We conduct  limited  exploration  activities for oil and natural gas reserves.
Instead,  we add  to our  oil  and  natural  gas  reserves  primarily  through
development and acquisitions. As a result, future oil and natural gas reserves
are highly  dependent on our success in  exploiting  existing  properties  and
acquiring additional reserves. We also distribute the majority of our net cash
flow  to  Unitholders  rather  than  reinvesting  it  in  reserves  additions.
Accordingly,  if  external  sources of  capital,  including  the  issuance  of
additional  Trust  Units,   become  limited  or  unavailable  on  commercially
reasonable  terms,  our ability to make the necessary  capital  investments to
maintain or expand its oil and natural gas reserves  will be impaired.  To the
extent that we are required to use cash flow to finance  capital  expenditures
or property acquisitions, the level of cash flow available for distribution to
Unitholders will be reduced. Additionally, we cannot guarantee that we will be
successful in developing  additional reserves or acquiring additional reserves
on  terms  that  meet  our  investment  objectives.   Without  these  reserves
additions,  our reserves will deplete and as a consequence,  either production
from, or the average  reserves life of, our  properties  will decline.  Either

<PAGE>
                                      51


decline  may  result  in a  reduction  in the  value of Trust  Units  and in a
reduction in cash available for distributions to Unitholders.

OPERATIONAL MATTERS

The operation of oil and gas wells  involves a number of operating and natural
hazards  which  may  result  in  blowouts,   environmental  damage  and  other
unexpected  or  dangerous  conditions  resulting  in damage to us and possible
liability to third parties.  We carry insurance policies to provide protection
for our working  interests  in the  properties  which cover  property  damage,
general  liability  and, for certain  properties,  business  interruption.  We
determine the ongoing level,  type and maintenance of insurance based upon the
availability  and cost of such  insurance  and our  perception  of the risk of
loss. We may become liable for damages  arising from such events against which
we cannot insure or against  which we may elect not to insure  because of high
premium costs or other  reasons.  Costs  incurred to repair such damage or pay
such liabilities will reduce royalty income.

Continuing  production  from a property,  and to some extent the  marketing of
production  therefrom,  are largely dependent upon the ability of the operator
of the property.  Operating costs on most  properties have increased  steadily
over recent years. To the extent the operator fails to perform these functions
properly,  revenue may be reduced.  Payments from  production  generally  flow
through the  operator and there is a risk of delay and  additional  expense in
receiving such revenues if the operator becomes insolvent.  A reduction of the
royalty income could result in such circumstances.

EXPANSION OF OPERATIONS

Our operations and expertise are currently focused on conventional oil and gas
production and development in the Western Canadian  Sedimentary  Basin. In the
future, we may acquire oil and gas properties outside this geographic area. In
addition,  the Trust  Indenture  does not limit our  activities to oil and gas
production and development,  and we could acquire other energy related assets,
such as oil and natural gas processing plants or pipelines,  or an interest in
an oil sands project.  Expansion of our activities  into new areas may present
new additional risks or alternatively,  significantly increase the exposure to
one or more of the present risk factors which may adversely  affect our future
operational and financial conditions.

NON-RESIDENT OWNERSHIP OF TRUST UNITS

In order for us to  maintain  our status as a mutual  fund trust under the Tax
Act, we must not be  established  or  maintained  primarily for the benefit of
non-residents of Canada (non-residents) within the meaning of the Tax Act. The
Trust  Indenture  provides  that  if at any  time we  become  aware  that  the
beneficial  owners of 50 percent or more of the Trust  Units then  outstanding
are or may be  non-residents  or that such a situation is  imminent,  we shall
take such action as may be necessary to carry out the foregoing intention. See
"Our Information - Limitations on Non-resident Ownership".

ACCOUNTING WRITE-DOWNS AS A RESULT OF GAAP

Canadian  Generally  Accepted  Accounting  Principles  ("GAAP")  require  that
management apply certain  accounting  policies and make certain  estimates and
assumptions  which  affect  reported  amounts  in our  consolidated  financial
statements.  The  accounting  policies  may result in non-cash  charges to net
income  and  write-downs  of net  assets  in the  financial  statements.  Such
non-cash charges and write-downs may be viewed  unfavourably by the market and
may result in an  inability  to borrow funds and/or may result in a decline in
the Trust Unit price.

<PAGE>
                                      52


Under  GAAP,  the net  amounts at which  petroleum  and natural gas costs on a
property or project  basis are carried  are  subject to a  cost-recovery  test
which is based in part upon estimated future net cash flows from reserves.  If
net capitalized costs exceed the estimated  recoverable  amounts, we will have
to charge the amounts of the excess to earnings. A decline in the net value of
oil and natural gas  properties  could cause  capitalized  costs to exceed the
cost ceiling, resulting in a charge against earnings. The net value of oil and
gas  properties  are highly  dependent upon the prices of oil and natural gas.
See "Risk Factors - Volatility of Oil and Natural Gas Prices".

GAAP  requires  that  goodwill  balances  be assessed  at least  annually  for
impairment  and that any  permanent  impairment  be charged to net  income.  A
permanent reduction in reserves, decline in commodity prices, and/or reduction
in the Trust Unit price may indicate goodwill  impairment.  As at December 31,
2005 we had $157.592 million recorded on its balance sheet as goodwill arising
out of our acquisition of Star Oil & Gas Ltd. An impairment  would result in a
write-down of the goodwill value and a non-cash charge against net income. The
calculation  of  impairment  value is  subject  to  management  estimates  and
assumptions.

New GAAP surrounding accounting for derivatives may result in non-cash charges
against  net  income  as a  result  of  changes  in the fair  market  value of
derivative instruments.  A decrease in the fair market value of the derivative
instruments  as the result of  fluctuations  in  commodity  prices and foreign
exchange rates may result in a write-down of net assets and a non-cash  charge
against net income.  Such write-downs and non-cash charges may be temporary in
nature if the fair market value subsequently increases.

ENVIRONMENTAL CONCERNS

The oil and  natural  gas  industry  is  subject to  environmental  regulation
pursuant  to  local,  provincial  and  federal  legislation.  A breach of such
legislation  may result in the  imposition  of fines or  issuance  of clean up
orders in respect of us or our properties.  Such legislation may be changed to
impose higher  standards and  potentially  more costly  obligations on us. See
"Industry   Regulations  -   Environmental   Regulation".   Although  we  have
established  a  reclamation  fund for the  purpose  of funding  our  currently
estimated  future  environmental  and  reclamation  obligations  based  on our
current  knowledge,  there can be no assurance that we will be able to satisfy
our actual future environmental and reclamation obligations.

In December 2002 the  Government of Canada  ratified the Kyoto Protocol and it
became legally binding on February 16, 2005. This protocol calls for Canada to
reduce its  greenhouse gas emissions to 6 percent below 1990 levels during the
period between 2008 and 2012. See "Risk Factors - Kyoto Protocol" below.

KYOTO PROTOCOL

Canada is a signatory to the United  Nations  Framework  Convention on Climate
Change and has  ratified  the Kyoto  Protocol  established  thereunder  to set
legally  binding  targets to reduce  nationwide  emissions of carbon  dioxide,
methane, nitrous oxide and other so-called "greenhouse gases". Our exploration
and production  facilities and other operations and activities emit greenhouse
gases that may subject us to  legislation  regulating  emissions of greenhouse
gases.  The  Government  of Canada has put  forward a Climate  Change Plan for
Canada which suggests  further  legislation will set greenhouse gases emission
reduction  requirements for various industrial  activities,  including oil and
gas exploration  and production.  While the protocol became legally binding on
February  16,  2005,  details  of any  specific  requirements  have  not  been
released. However, the Canadian Association of Petroleum Producers has secured
specific  non-binding  limitations from the Government of Canada on reductions
required by the oil and gas  industry  and the cost  thereof.  On the basis of
these  limitations,  the impact of the Kyoto  Protocol  on our  operations  is
currently not expected to be material.

<PAGE>
                                      53


Future  federal  legislation,  together  with  provincial  emission  reduction
requirements,  such as those  proposed in Alberta's Bill 37 Climate Change and
Emissions  Management,  may require the  reduction  of  emissions or emissions
intensity of our operations  and  facilities  beyond what was agreed to by the
Canadian Association of Petroleum  Producers.  The direct or indirect costs of
these regulations may adversely affect our business.

DEBT SERVICE

Amounts paid in respect of interest and  principal on debt incurred in respect
of the properties will reduce royalty income. Variations in interest rates and
scheduled  principal  repayments  could result in  significant  changes in the
amount  required to be applied to debt service before payment of the Royalties
and  interest  on the  Long  Term  Notes  and  distributable  income.  Certain
covenants of the agreements with our lenders may also limit  distributions  to
us from our  subsidiaries.  Although we believe the credit  facilities will be
sufficient for our immediate requirements,  there can be no assurance that the
amount  will  be  adequate  for  our  future  financial  obligations  or  that
additional funds will be able to be obtained. For more information, see "Other
Information Relating To Our Business - Borrowing".

The lenders have or will be provided with security over  substantially  all of
our assets.  If we become unable to pay our debt service  charges or otherwise
commit an event of default such as bankruptcy,  the lender may foreclose on or
sell the properties  free from or together with the Royalties.  The payment of
interest and principal on debt may also result in us having taxable income and
cash taxes  payable as  taxable  income  would no longer be reduced by royalty
payments at the time debt repayment occurs.

DELAY IN CASH DISTRIBUTIONS

In addition to the usual  delays in payment by  purchasers  of oil and natural
gas to the operators of the  properties,  and by the operator to us,  payments
between  any of such  parties may also be delayed by  restrictions  imposed by
lenders, delays in the sale or delivery of products,  delays in the connection
of wells to a gathering system,  blowouts or other accidents,  recovery by the
operator  of expenses  incurred  in the  operation  of the  properties  or the
establishment by the operator of reserves for such expenses.

RELIANCE ON MANAGEMENT

Unitholders   will  be  dependent  on  our   management   in  respect  of  the
administration  and management of all matters relating to our properties,  the
Royalties and Trust Units. As of December 31, 2005, we operated  approximately
73 percent of the total daily production of our properties.  Investors who are
not willing to rely on our management should not invest in Trust Units.

DEPLETION OF RESERVES

Distributions  of  distributable  income  in  respect  of  properties,  absent
commodity  price  increases  or cost  effective  acquisition  and  development
activities,  will  decline  over time in a manner  consistent  with  declining
production from typical oil, natural gas and natural gas liquids reserves.  We
will not be  reinvesting  cash  flow in the  same  manner  as  other  industry
participants  as we conduct only minimal  exploratory  activities;  nor to the
same extent as other industry participants as one of our main objectives is to
maximize long-term distributions.  Accordingly, absent capital injections, our
initial  production  levels  and  reserves  will  decline  and  the  level  of
distributable income will be reduced.

Our future oil and natural gas reserves and production, and therefore our cash
flows, will be highly dependent on our success in exploiting our reserves base
and  acquiring  additional   reserves.   Without  reserves  additions  through
acquisition  or  development  activities,  our  reserves and  production  will
decline over time as reserves are exploited.

<PAGE>
                                      54


To the extent that  external  sources of capital,  including  the  issuance of
additional Trust Units become limited or unavailable,  our ability to make the
necessary  capital  investments  to maintain or expand our oil and natural gas
reserves will be impaired. To the extent that we are required to use cash flow
to  finance  capital  expenditures  or  property  acquisitions,  the  level of
distributable income will be reduced.

There  can be no  assurance  that we  will  be  successful  in  developing  or
acquiring additional reserves on terms that meet our investment objectives.

NET ASSET VALUE

The net asset value of our assets from time to time will vary dependent upon a
number of factors  beyond the  control of  management,  including  oil and gas
prices.  The  trading  prices  of the  Trust  Units  from time to time is also
determined  by a number of factors  which are beyond the control of management
and such trading prices may be greater than the net asset value of our assets.

ADDITIONAL FINANCING

In the normal course of making capital  investments to maintain and expand our
oil and gas reserves additional Trust Units are issued from treasury which may
result in a decline in production  per Trust Unit and reserves per Trust Unit.
Additionally, from time to time we issue Trust Units from treasury in order to
reduce debt and maintain a more optimal capital  structure.  Conversely to the
extent that external sources of capital,  including the issuance of additional
Trust Units become limited or  unavailable,  our ability to make the necessary
capital  investments  to maintain or expand our oil and gas  reserves  will be
impaired.  To the  extent  that we are  required  to use cash flow to  finance
capital  expenditures or property  acquisitions or to pay debt service charges
or to reduce debt, the level of distributable income will be reduced.

COMPETITION

There  is  strong  competition  relating  to all  aspects  of the  oil and gas
industry.  There  are  numerous  trusts in the oil and gas  industry,  who are
competing for the  acquisitions  of  properties  with longer life reserves and
properties with  exploitation  and development  opportunities.  As a result of
such increasing competition,  it will be more difficult to acquire reserves on
beneficial  terms.  We also  compete  for  reserves  acquisitions  and skilled
industry  personnel with a substantial  number of other oil and gas companies,
many of which have significantly greater financial and other resources than we
do.

RETURN OF CAPITAL

Trust Units will have no value when reserves from the properties can no longer
be economically produced and, as a result, cash distributions do not represent
a "yield" in the  traditional  sense and are not  comparable to bonds or other
fixed yield  securities,  where investors are entitled to a full return of the
principal  amount of debt on maturity  in  addition to a return on  investment
through  interest  payments.  Distributions  represent  a blend of  return  of
Unitholders initial investment and a return on Unitholders initial investment.

Unitholders have a limited right to require a repurchase of their Trust Units,
which is referred to as a redemption  right.  See "Our  Information - Right of
Redemption."  It is  anticipated  that the  redemption  right  will not be the
primary mechanism for Unitholders to liquidate their investment.  The right to
receive cash in connection  with a redemption is subject to  limitations.  Any
securities  which may be  distributed  IN SPECIE to  Unitholders in connection
with a redemption may not be listed on any stock exchange and a market may not
develop for such  securities.  In addition,  there may be resale  restrictions
imposed  by  law  upon  the  recipients  of  the  securities  pursuant  to the
redemption right.

<PAGE>
                                      55


NATURE OF TRUST UNITS

The Trust  Units do not  represent  a  traditional  investment  in the oil and
natural  gas sector and  should  not be viewed by  investors  as shares in ARC
Resources.  The Trust  Units  represent  a  fractional  interest in the Trust.
Corporate  law does not  govern the Trust and the  rights of  Unitholders.  As
holders  of Trust  Units,  Unitholders  will not  have  the  statutory  rights
normally associated with ownership of shares of a corporation  including,  for
example,  the right to bring oppression or derivative  actions.  The rights of
Unitholders are specifically  set forth in the Trust  Indenture.  In addition,
trusts are not  defined as  recognized  entities  within  the  definitions  of
legislation such as the BANKRUPTCY AND INSOLVENCY ACT (Canada), the COMPANIES'
CREDITORS  ARRANGEMENT  ACT  (Canada)  and in some  cases the  WINDING  UP AND
RESTRUCTURING  ACT  (Canada).  As a result,  in the event of an  insolvency or
restructuring,  a  Unitholder's  position as such may be quite  different than
that of a shareholder  of a  corporation.  The Trust's sole assets will be the
royalty and other  investments  in  securities.  The price per Trust Unit is a
function of anticipated  distributable  income, the properties  acquired by us
and our ability to effect  long-term  growth in our value. The market price of
the Trust Units will be sensitive to a variety of market conditions including,
but not limited to, interest rates and our ability to acquire suitable oil and
natural gas properties.  Changes in market conditions may adversely affect the
trading price of the Trust Units.

THE TRUST UNITS ARE NOT  "DEPOSITS"  WITHIN THE MEANING OF THE CANADA  DEPOSIT
INSURANCE CORPORATION ACT (CANADA) AND ARE NOT INSURED UNDER THE PROVISIONS OF
THAT ACT OR ANY OTHER  LEGISLATION.  FURTHERMORE,  WE ARE NOT A TRUST  COMPANY
AND,  ACCORDINGLY,  ARE NOT  REGISTERED  UNDER  ANY  TRUST  AND  LOAN  COMPANY
LEGISLATION  AS WE DO NOT  CARRY ON OR INTEND  TO CARRY ON THE  BUSINESS  OF A
TRUST COMPANY.

UNITHOLDER LIMITED LIABILITY

The  Trust  Indenture  provides  that no  Unitholder  will be  subject  to any
liability in  connection  with us or our  obligations  and affairs and, in the
event that a court determines Unitholders are subject to any such liabilities,
the liabilities will be enforceable  only against,  and will be satisfied only
out of our assets. Pursuant to the Trust Indenture, we will indemnify and hold
harmless  each  Unitholder  from any costs,  damages,  liabilities,  expenses,
charges and losses  suffered by a Unitholder  resulting from or arising out of
such Unitholder not having such limited liability.

The Trust Indenture provides that all written  instruments signed by or on our
behalf must contain a provision to the effect that such obligation will not be
binding upon Unitholders personally.  The principal investment of the Trust is
the royalty  agreements which contain such provisions.  Personal liability may
also arise in respect of claims against us that do not arise under  contracts,
including  claims  in tort,  claims  for  taxes  and  possibly  certain  other
statutory  liabilities.  The  possibility  of any  personal  liability of this
nature  arising is  considered  unlikely.  The  INCOME  TRUSTS  LIABILITY  ACT
(Alberta)  came into force on July 1, 2004.  The  legislation  provides that a
unitholder  will  not be,  as a  beneficiary,  liable  for any  act,  default,
obligation or liability of the trustee that arises after the legislation  came
into force.

Our operations  will be conducted,  upon the advice of counsel,  in such a way
and in such  jurisdictions as to avoid as far as possible any material risk of
liability on Unitholders for claims against us.

TITLE TO PROPERTIES

The rights to produce petroleum and gas substances are subject to an agreement
between us and the owners of the mineral resource. The terms of this agreement
contains certain ongoing  obligations and commitments  that, if not fulfilled,
can result in the  forfeiture  of the  agreement to the mineral right owner or
the payment of cash compensation.

<PAGE>
                                      56


Although satisfactory title reviews are generally conducted in accordance with
industry standards,  such reviews do not guarantee or certify that a defect in
the chain of title may not arise to defeat our claim to certain properties. In
certain  situations  there may be multiple  mineral  resource  owners claiming
various ownership over the same parcel of land. Any settlement of a dispute of
ownership may result in the  forfeiture  of the mineral  resource by us or the
payment of cash compensation to the mineral resource owner.

                        TRANSFER AGENTS AND REGISTRARS

The  transfer  agent and  registrar  for the Trust Units and the  Exchangeable
Shares is  Computershare  Trust Company of Canada at its principal  offices in
Calgary and Toronto.

                              MATERIAL CONTRACTS

The following  comprises  particulars of every material  contract to the Trust
that was entered into within the most recently  completed  financial  year, or
entered into before the most recently completed  financial year which is still
in effect,  other  than a  contract  entered  into in the  ordinary  course of
business:

1.   Trust Indenture.  For information,  see "Our  Information" and "Corporate
     Governance".

2.   Exchangeable Share Provisions. For information, see "Share Capital of ARC
     Resources - Exchangeable Shares".

3.   Exchangeable Share Voting and Exchange Trust Agreement.  For information,
     see "Share Capital of ARC Resources - Exchangeable Shares".

4.   Exchangeable Share Support Agreement. For information, see "Share Capital
     of ARC Resources - Exchangeable Shares".

Copies of each of these documents have been filed on SEDAR at www.sedar.com.

                              INTEREST OF EXPERTS

There is no person or company whose  profession or business gives authority to
a statement made by such person or company and who is named as having prepared
or  certified a  statement,  report or  valuation  described  or included in a
filing, or referred to in a filing,  made under National  Instrument 51-102 by
us during,  or related to, our most recently  completed  financial  year other
than GLJ, our independent  engineering  evaluator,  and Deloitte & Touche LLP,
our auditors.  The interest of GLJ in our Trust Units and Exchangeable  Shares
represents and represented at the time it prepared the GLJ Report less than 1%
of each of the issued and  outstanding  Trust  Units or  Exchangeable  Shares.
Deloitte & Touche LLP is the  auditor of the Trust and is  independent  within
the meaning of the Rules of Professional Conduct of the Institute of Chartered
Accountants, Alberta.

In  addition,  none  of the  aforementioned  persons  or  companies,  nor  any
director,  officer  or  employee  of  any  of the  aforementioned  persons  or
companies,  is or is  expected  to be  elected,  appointed  or  employed  as a
director,  officer or employee of ARC  Resources or of any of our associate or
affiliate entities. Allan R. Twa, the Corporate Secretary of ARC Resources, is
a partner of Burnet,  Duckworth & Palmer  LLP,  which law firm  renders  legal
services to us.

<PAGE>
                                      57


                            ADDITIONAL INFORMATION

Additional  information  including  remuneration and indebtedness of directors
and  officers  of  ARC  Resources,  principal  holders  of  the  Trust  Units,
Exchangeable  Shares and rights to purchase  Trust Units,  is contained in the
Information  Circular  - Proxy  Statement  of the Trust  which  relates to the
Annual  and  Special  Meeting  of  Unitholders  to be held  on May  15,  2006.
Additional  financial  information is provided in our  consolidated  financial
statements and accompanying  management's discussion and analysis for the year
ended December 31, 2005, which have been filed on SEDAR at www.sedar.com.



<PAGE>


                                  APPENDIX A

      REPORT ON RESERVES DATA BY INDEPENDENT QUALIFIED RESERVES EVALUATOR

To the board of directors of ARC Resources Ltd. (the "Company"):

1.   We have  prepared an  evaluation  of the  Company's  reserves  data as at
     December 31, 2005. The reserves data consist of the following:

     (a)      (i)      proved and proved plus  probable  oil and gas  reserves
                       estimated as at December 1, 2005 using forecast  prices
                       and costs; and

              (ii)     the related estimated future net revenue; and

     (b)      (i)      proved oil and gas  reserves  estimated  as at December
                       31, 2005 using constant prices and costs; and

              (ii)     the related estimated future net revenue.

2.   The reserves data are the responsibility of the Company's management. Our
     responsibility is to express an opinion on the reserves data based on our
     evaluation.

     We carried out our evaluation in accordance with standards set out in the
     Canadian Oil and Gas Evaluation  Handbook (the "COGE Handbook")  prepared
     jointly  by  the  Society  of  Petroleum  Evaluation  Engineers  (Calgary
     Chapter)  and the Canadian  Institute  of Mining,  Metallurgy & Petroleum
     (Petroleum Society).

3.   Those standards  require that we plan and perform an evaluation to obtain
     reasonable assurance as to whether the reserves data are free of material
     misstatement.  An evaluation also includes assessing whether the reserves
     data are in accordance with  principles and definitions  presented in the
     COGE Handbook.

4.   The following  table sets forth the estimated  future net revenue (before
     deduction of income taxes)  attributed to proved plus probable  reserves,
     estimated using forecast prices and costs and calculated using a discount
     rate  of 10  percent,  included  in the  reserves  data  of  the  Company
     evaluated by us for the year ended  December 31, 2005, and identifies the
     respective portions thereof that we have audited,  evaluated and reviewed
     and reported on to the Company's board of directors:

<TABLE>
<CAPTION>
                                                                   NET PRESENT VALUE OF FUTURE NET REVENUE
                                   LOCATION OF RESERVES  (BEFORE INCOME TAXES, 10% DISCOUNT RATE, MILLIONS DOLLARS)
DESCRIPTION AND PREPARATION DATE   (COUNTRY OR FOREIGN   ----------------------------------------------------------
      OF EVALUATION REPORT           GEOGRAPHIC AREA)        AUDITED       EVALUATED      REVIEWED        TOTAL
      --------------------           ----------------        -------       ---------      --------        -----

        <S>                               <C>                  <C>           <C>             <C>          <C>
        February 1, 2006                  Canada                 -            3,891            -           3,891
</TABLE>

5.   In our opinion,  the reserves data respectively  evaluated by us have, in
     all material  respects,  been  determined and are in accordance  with the
     COGE Handbook.

6.   We have no  responsibility  to update  this  evaluation  for  events  and
     circumstances occurring after the preparation dates.

<PAGE>
                                     A-2


7.   Because the reserves data are based on judgments regarding future events,
     actual results will vary and the variations may be material.

Executed as to our report referred to above:



GLJ  Petroleum Consultants Ltd.                         Dated February 23, 2006
Calgary, Alberta, Canada


/s/ James H. Willmon
------------------------
 James H. Willmon, P.Eng
 Vice President




<PAGE>


                                  APPENDIX B

                     REPORT OF MANAGEMENT AND DIRECTORS ON
                      RESERVES DATA AND OTHER INFORMATION

Management of ARC Resources Ltd. (the "Company") on behalf of ARC Energy Trust
(the  "Trust")  are   responsible   for  the  preparation  and  disclosure  of
information with respect to the Company's and the other Trust's  subsidiaries'
oil and gas activities in accordance with securities regulatory  requirements.
This information includes reserves data, which consist of the following:

     (a)      (i)      proved and proved plus  probable  oil and gas  reserves
                       estimated as at December 31, 2005 using forecast prices
                       and costs; and

              (ii)     the related estimated future net revenue; and

     (b)      (i)      proved oil and gas  reserves  estimated  as at December
                       31, 2005 using constant prices and costs; and

              (ii)     the related estimated future net revenue.

An independent  qualified  reserves  evaluator has evaluated the Company's and
the other Trust's  subsidiaries'  reserves data. The report of the independent
qualified reserves evaluator is presented below.

The Reserves Committee of the board of directors of the Company has

     (c)      reviewed the Company's  procedures for providing  information to
              the independent qualified reserves evaluator;

     (d)      met  with  the  independent   qualified  reserves  evaluator  to
              determine  whether any restrictions  affected the ability of the
              independent  qualified  reserves  evaluator  to  report  without
              reservation; and

     (e)      reviewed the reserves data with  management and the  independent
              qualified reserves evaluator.

The Reserves  Committee of the board of directors  has reviewed the  Company's
procedures for assembling and reporting other information  associated with oil
and gas  activities and has reviewed that  information  with  management.  The
board of  directors  has, on the  recommendation  of the  Reserves  Committee,
approved

     (f)      the content and filing with securities regulatory authorities of
              the reserves data and other oil and gas information;

     (g)      the filing of the report of the independent  qualified  reserves
              evaluator on the reserves data; and

     (h)      the content and filing of this report.


<PAGE>
                                     B-2


Because the reserves  data are based on  judgments  regarding  future  events,
actual results will vary and the variations may be material.

/s/ John P. Dielwart                      /s/ Doug Bonner
-------------------------------------     -----------------------------------
JOHN P. DIELWART                          DOUG BONNER
President and Chief Executive Officer     Senior Vice-President, Corporate
                                          Development


/s/ Frederic Coles                        /s/ Fred J. Dyment
-------------------------------------     -----------------------------------
FREDERIC COLES                            FRED J. DYMENT
Director and Chairman of the Reserves     Director and Member of the Reserves
Committee                                 Committee



March 22, 2006


<PAGE>


                                  APPENDIX C

                        MANDATE OF THE AUDIT COMMITTEE

ROLE AND OBJECTIVE

The Audit Committee (the "Committee") is a committee of the Board of Directors
of  ARC  Resources  Ltd.   ("ARL")  to  which  the  Board  has  delegated  its
responsibility  for  oversight  of the nature  and scope of the annual  audit,
management's   reporting  on  internal  accounting  standards  and  practices,
financial  information  and  accounting  systems  and  procedures,   financial
reporting and statements and recommending, for Board of Director approval, the
audited  financial   statements  and  other  mandatory   disclosure   releases
containing  financial  information.  The  objectives  of the  Committee,  with
respect to ARL and ARC Energy Trust (the  "Trust")  (hereinafter  collectively
referred to as "ARC"), are as follows:

o    To assist  Directors  to meet  their  responsibilities  in respect of the
     preparation and disclosure of the financial statements of ARC and related
     matters.

o    To provide better communication between directors and external auditors.

o    To ensure the external auditors' independence.

o    To increase the credibility and objectivity of financial reports.

o    To strengthen the role of the outside  directors by facilitating in depth
     discussions  between directors on the Committee,  management and external
     auditors.

MANDATE AND RESPONSIBILITIES OF COMMITTEE

o    It is the  responsibility of the Committee to satisfy itself on behalf of
     the Board with respect to ARC's internal control systems:

     o    identifying, monitoring and mitigating business risks; and

     o    ensuring compliance with legal, ethical and regulatory requirements.

o    It is a primary  responsibility  of the  Committee  to review  the annual
     financial  statements  of ARC prior to their  submission  to the Board of
     Directors for approval. The process should include but not be limited to:

     o    reviewing changes in accounting principles, or in their application,
          which may have a material  impact on the  current  or future  years'
          financial statements;

     o    reviewing significant accruals,  reserves or other estimates such as
          the ceiling test calculation;

     o    reviewing   accounting   treatment   of  unusual  or   non-recurring
          transactions;

     o    reviewing  the Trust's  status as a "mutual  fund  trust"  under the
          INCOME TAX ACT (Canada);

     o    ascertaining  compliance  with covenants  under loan  agreements and
          Trust Indenture;

     o    reviewing   financial   reporting   relating  to  asset   retirement
          obligations;

     o    reviewing disclosure requirements for commitments and contingencies;

<PAGE>
                                     C-2


     o    reviewing  adjustments raised by the external  auditors,  whether or
          not included in the financial statements;

     o    reviewing unresolved differences between management and the external
          auditors;

     o    obtain  explanations  of  significant   variances  with  comparative
          reporting periods; and

     o    determine   through   inquiry  if  there  are  any   related   party
          transactions  and ensure the nature and extent of such  transactions
          are properly disclosed.

o    The  Committee  is  to  review  the  financial   statements  and  related
     information included in prospectuses,  management discussion and analysis
     (MD&A),  information  circular-proxy  statements  and annual  information
     forms (AIF), prior to Board approval.

o    With respect to the  appointment of external  auditors by the Board,  the
     Committee shall:

     o    be directly  responsible  for  overseeing  the work of the  external
          auditors  engaged for the purpose of issuing an auditors'  report or
          performing  other  audit,  review or attest  services for the Trust,
          including the resolution of disagreements between management and the
          external auditor regarding financial reporting;

     o    review  management's  recommendation for the appointment of external
          auditors and recommend to the Board appointment of external auditors
          and the compensation of the external auditors;

     o    review the terms of engagement of the external  auditors,  including
          the appropriateness and reasonableness of the auditors' fees;

     o    when there is to be a change in auditors,  review the issues related
          to the change and the  information  to be included  in the  required
          notice to securities regulators of such change; and

     o    review and  approve  any  non-audit  services  to be provided by the
          external  auditors' firm and consider the impact on the independence
          of the auditors.

o    Review with external  auditors (and internal  auditor if one is appointed
     by ARC) their  assessment of the internal  controls of ARC, their written
     reports  containing  recommendations  for  improvement,  and management's
     response and follow-up to any identified weaknesses.  The Committee shall
     also review  annually  with the  external  auditors  their plan for their
     audit and, upon completion of the audit, their reports upon the financial
     statements of ARC and its subsidiaries.

o    Review all public disclosure  containing  audited or unaudited  financial
     information before release.

o    Review financial reporting relating to risk exposure.

o    Review ARC's plans and strategies  around investment  practices,  banking
     performance and treasury risk management.

o    Satisfy  itself that adequate  procedures  are in place for the review of
     the Trust's public  disclosure of financial  information from the Trust's
     financial  statements  and  periodically  assess  the  adequacy  of those
     procedures.

<PAGE>
                                     C-3


o    Establish procedures for:

     o    the receipt,  retention and treatment of complaints  received by the
          Trust  regarding   accounting,   internal  accounting  controls,  or
          auditing matters; and

     o    the confidential,  anonymous submission by employees of the Trust of
          concerns regarding questionable accounting or auditing matters.

o    Review and approve ARC's hiring policies  regarding  partners,  employees
     and former partners and employees of the present and external auditors of
     ARC.

o    Review any other matters that the Audit  Committee feels are important to
     its mandate or that the Board chooses to delegate to it.

COMPOSITION

o    This Committee shall be composed of at least three individuals  appointed
     by the Board from  amongst  its  members,  all of which  members  will be
     independent  (within the meaning of Multilateral  Instrument 52-110 Audit
     Committees)  unless the Board  determines  to rely on an  exemption in NI
     52-110.  "Independent"  generally  means free from any  business or other
     direct or indirect material relationship with ARC that could, in the view
     of the Board of Directors,  reasonably interfere with the exercise of the
     member's independent judgment.

o    The Secretary to the Board shall act as Secretary of the Committee.

o    A quorum shall be a majority of the members of the Committee.

o    All of the members must be financially  literate within the meaning of NI
     52-110  unless the Board has  determined  to rely on an  exemption  in NI
     52-110.  Being  "financially  literate" means members have the ability to
     read and understand a set of financial  statements that present a breadth
     and  level  of  complexity  of  accounting   issues  that  are  generally
     comparable to the breadth and complexity of issues that can reasonably be
     expected to be raised by the Trust's financial statements.

MEETINGS

o    The  Committee  shall meet at least four times per year  and/or as deemed
     appropriate by the Committee Chair.

o    The  Committee  shall  meet not less than  quarterly  with the  auditors,
     independent of the presence of management.

o    Agendas,  with input from  management,  shall be  circulated to Committee
     members  and  relevant   management   personnel   along  with  background
     information on a timely basis prior to the Committee meetings.

o    Minutes  of each  meeting  shall  be  prepared  by the  Secretary  to the
     Committee.

o    The Chief  Executive  Officer  and the Chief  Financial  Officer or their
     designates  shall be available to attend at all meetings of the Committee
     upon the invitation of the Committee.

<PAGE>
                                     C-4


o    The Controller,  Treasurer and such other staff as appropriate to provide
     information to the Committee shall attend meetings upon invitation by the
     Committee.

REPORTING / AUTHORITY

o    Following  each meeting,  in addition to a verbal  report,  the Committee
     will  report to the Board by way of  providing  copies of the  minutes of
     such Committee  meeting at the next Board meeting after a meeting is held
     (these may still be in draft form).

o    Supporting  schedules and information  reviewed by the Committee shall be
     available for examination by any director.

o    The  Committee  shall have the  authority to  investigate  any  financial
     activity of the Corporation and to communicate directly with the internal
     and external auditors. All employees are to cooperate as requested by the
     Committee.

o    The  Committee  may,  with the prior  approval  of the  Policy  and Board
     Governance  Committee,  retain,  and set and  pay the  compensation  for,
     persons having special expertise and/or obtain  independent  professional
     advice to assist in  fulfilling  its duties and  responsibilities  at the
     expense of ARC.